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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION
)
)
Docket No. RD12-_____
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
FAC-001-1, FAC-003-3, PRC-004-2.1a and PRC-005-1.1b
Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Charles A. Berardesco
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
charles.berardesco@nerc.net
Stacey Tyrewala
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
holly.hawkins@nerc.net
stacey.tyrewala@nerc.net
July 30, 2012
TABLE OF CONTENTS
I. Executive Summary………………………………………………………………………….. 4
II. Notices and Communications………………………………………………………………... 6
III. Background …………………………………………………………………………………. 6
a.
b.
c.
d.
Regulatory Framework
NERC Reliability Standards Development Procedure
History of Related Commission Orders
History of Project 2010-07
IV. Justification for Approval of the Proposed Reliability Standards………………………… 18
a. Basis and Purpose of Proposed Standard and Improvements in this Revision
b. Enforceability of the Proposed Reliability Standard
V. Summary of the Reliability Standard Development Proceedings………………………….. 27
a.
b.
c.
d.
e.
f.
g.
h.
i.
SAR Development
Overview of the Standard Drafting Team
First Posting
Second Posting and Initial Ballot
Third Posting, Recirculation Ballot and Appeal
Board of Trustees Approval of FAC-001-1 and PRC-004-2.1a
Fourth Posting, Initial and Successive Ballots
Fifth Posting, Recirculation Ballot
Board of Trustees Approval of FAC-003-3 and PRC-005-1.1b
VI. Conclusion……………………………………………………………………………………. 35
Exhibit A — Order No. 672 Criteria
Exhibit B — Reliability Standards submitted for Approval
Exhibit C — Technical Justification Resource Document
Exhibit D — Implementation Plan for Reliability Standard submitted for Approval
Exhibit E — Consideration of Comments
Exhibit F — Analysis of how VRFs and VSLs Were Determined Using Commission Guidelines
Exhibit G — Record of Development of Proposed Reliability Standard
Exhibit H — Standard Drafting Team Roster for NERC Standards Development Project 2010-07
i
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION
)
)
Docket No. RD12-____
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
FAC-001-1, FAC-003-3, PRC-004.21a and PRC-005-1.1b
The North American Electric Reliability Corporation (“NERC”) 1 hereby requests
the Federal Energy Regulatory Commission (“FERC” or the “Commission”) to approve,
in accordance with Section 215(d)(1) of the Federal Power Act (“FPA”) 2 and Section
39.5 of the Commission’s regulations, 18 C.F.R. § 39.5 (2012), the proposed Reliability
Standards — FAC-001-1 – Facility Connection Requirements, FAC-003-3 –
Transmission Vegetation Management, PRC-004-2.1a – Analysis and Mitigation of
Transmission and Generation Protection System Misoperations and PRC-005-1.1b Transmission and Generation Protection System Maintenance and Testing, which were
approved by the NERC Board of Trustees 3 on February 9, 2012 and May 9, 2012. 4
The proposed Reliability Standards improve reliability by addressing the
application of Reliability Standards to generator interconnection Facilities (also referred
1
NERC has been certified by the Commission as the electric reliability organization (“ERO”) in
accordance with Section 215 of the Federal Power Act. The Commission certified NERC as the ERO in its
order issued July 20, 2006 in Docket No. RR06-1-000. North American Electric Reliability Corp., 116
FERC ¶ 61,062 (2006) (“ERO Certification Order”).
2
16 U.S.C. § 824o (2012).
3
FAC-001-1 and PRC-004-2.1a were approved on February 9, 2012; FAC-003-3 and PRC-0051.1b were approved on May 9, 2012.
4
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary
of Terms Used in NERC Reliability Standards, available here:
http://www.nerc.com/files/Glossary_of_Terms.pdf.
1
to as generator tie-lines), which will allow entities to clearly understand the scope of their
expected compliance responsibilities. The Reliability Standards set forth the
responsibilities of those Generator Owners and Generator Operators that own or operate a
generator interconnection Facility and interface with the portion of the Bulk Electric
System where Transmission Owners and Transmission Operators then take over
ownership and operating responsibility.
All Bulk Power System owners, operators and users are required to register with
NERC pursuant to Section 39.2 of the Commission’s regulations. 18 C.F.R. § 39.2
(2012). The process for registration is described in the NERC Rules of Procedure,
Section 500 and Appendix 5A. The NERC Compliance Registry is a listing of all
organizations registered and therefore subject to compliance with approved Reliability
Standards.
In the past, certain Generator Owners and Generator Operators with generator
interconnection Facilities have been registered with NERC as Transmission Owners and
Transmission Operators. 5 In several of these registration appeal proceedings, the
Commission has encouraged NERC, the Regional Entities and registered entities to
identify specific Reliability Standards with which Generator Owners and Generator
Operators must comply if they own and/or operate generator interconnection Facilities,
including transmission lines. In addition, in Order No. 693 (at P 98), the Commission
stated that it would consider Reliability Standard limitations on applicability based on
electric facility characteristics, once presented with such a proposal. In the instant filing,
NERC is proposing Commission approval of four Reliability Standards to be applicable
5
See e.g, New Harquahala Generating Co., LLC, 123 FERC ¶ 61,173 (2008); Cedar Creek Wind
Energy, LLC et al., 135 FERC ¶ 61,141 (2011).
2
to generators that would otherwise apply to the Transmission Owner and/or Transmission
Operator functions. This would obviate the need to register all generators as
Transmission Owners and/or Transmission Operators with respect to generator
interconnection Facilities, unless individual circumstances warrant otherwise.
Application of these four Reliability Standards would ensure generators are
focused on their primary functions-- to perform the duties associated with owning a
generation asset, and to operate their generation equipment (including interconnection
Facilities) in a reliable manner. Consistent with these considerations, the following
revisions are proposed to FAC-001-1, FAC-003-3, PRC-004-2.1a and PRC-00501.1b,
which would apply to all Generator Owners and Generator Operators that own or operate
generator interconnection Facilities:
•
FAC-001-1 requires a Generator Owner to document and publish Facility
connection requirements if and when it executes an Agreement to evaluate
the reliability impact of interconnecting a third party Facility to its existing
generation interconnection Facility.
•
FAC-003-3 requires a Generator Owner with a qualifying interconnection
Facility to perform vegetation management on the qualifying Facility.
•
PRC-004-2.1a makes clear that generator interconnection Facilities are
also the responsibility of Generator Owners in the context of this standard.
•
PRC-005-1.1b makes clear that generator interconnection Facilities are
also the responsibility of Generator Owners in the context of this standard.
NERC is hereby requesting approval of the proposed Reliability Standards, the
associated implementation plan, Violation Risk Factors (“VRFs”) and Violation Severity
3
Levels (“VSLs”), and retirement of currently effective Reliability Standards as detailed
below. Specifically, NERC requests approval of the following:
I.
•
Approval of the following Reliability Standards included in Exhibit B,
effective the first day of the first calendar quarter that is one year following
the effective date of a Final Rule in this docket:
o FAC-001-1
o FAC-003-3
•
Approval of the following Reliability Standards included in Exhibit B,
effective the first day following the effective date of a Final Rule in this
docket:
o PRC-004-2.1a
o PRC-005-1.1b
•
Approval of the implementation plans for the Reliability Standards which are
included in Exhibit D;
•
Approval of the retirement of the following Reliability Standards, effective
midnight immediately prior to the first day of the first calendar quarter that is
one year following the effective date of a Final Rule in this docket:
o FAC-001-0
o FAC-003-1
•
Approval of the retirement of the following Reliability Standards, effective
midnight immediately prior to the issuance of a Final Rule in this docket:
o PRC-004-2a
o PRC-005-1b
EXECUTIVE SUMMARY
The proposed Reliability Standards represent an improvement over the currently
effective standards because they ensure that there are no reliability gaps in (1) the
development of Facility connection requirements when a third party requests
interconnection to a Generator Owner Facility and (2) the performance of vegetation
management on Bulk Electric System Facilities. The proposed Reliability Standards also
clarify the responsibility for generator interconnection Facilities with respect to the
4
analysis and mitigation of protection system misoperations and protection system
maintenance and testing.
Collectively, these changes address the reliability gap regarding generator
interconnection Facilities for the vast majority of Generator Owners and Generator
Operators. Except as necessary on a fact-specific basis, these are the only standards that
need to be applied to Generator Owners and Generator Operators to ensure the
appropriate inclusion of generator interconnection Facilities in NERC’s Reliability
Standards.
The submission of this petition and any subsequent order by the Commission will
not have the effect of de-registering any entity from the NERC Compliance Registry.
Any changes to registration will continue to be governed by the NERC Rules of
Procedure and this petition does not affect the rights of any party thereunder.
5
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following: 6
Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Holly A. Hawkins*
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Stacey Tyrewala*
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
holly.hawkins@nerc.net
stacey.tyrewala@nerc.net
Charles A. Berardesco*
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
charles.berardesco@nerc.net
III.
BACKGROUND
a.
Regulatory Framework
By enacting the Energy Policy Act of 2005, 7 Congress entrusted the Commission
with the duties of approving and enforcing rules to ensure the reliability of the Nation’s
bulk power system, and with the duties of certifying an electric reliability organization
(“ERO”) that would be charged with developing and enforcing mandatory Reliability
Standards, subject to Commission approval. Section 215 of the FPA states that all users,
owners, and operators of the bulk power system in the United States will be subject to
Commission-approved Reliability Standards. 8
6
Persons to be included on the Commission’s service list are indicated with an asterisk. NERC
requests waiver of the Commission’s rules and regulations to permit the inclusion of more than two people
on the service list.
7
16 U.S.C. § 824o (2012).
8
See Section 215(b)(1)(“All users, owners and operators of the bulk-power system shall comply
with reliability standards that take effect under this section.”).
6
Section 215(d)(5) of the FPA authorizes the Commission to order the ERO to
submit a new or modified Reliability Standard. Pursuant to Section 215(d)(2) of the FPA
and Section 39.5(c) of the Commission’s regulations, the Commission will give due
weight to the technical expertise of the ERO with respect to the content of a Reliability
Standard. In Order No. 693, the Commission noted that it would defer to the “technical
expertise” of the ERO with respect to the content of a Reliability Standard and explained
that, through the use of directives, it provides guidance but does not dictate an outcome.
Rather, the Commission will consider an equivalent alternative approach provided that
the ERO demonstrates that the alternative will address the Commission’s underlying
concern or goal as efficiently and effectively as the Commission’s proposal, example, or
directive. 9
Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes to become
mandatory and enforceable in the United States, and each modification to a Reliability
Standard that the ERO proposes to be made effective. The Commission has the
regulatory responsibility to approve standards that protect the reliability of the bulk
power system and to ensure that such standards are just, reasonable, not unduly
discriminatory or preferential, and in the public interest.
Order No. 672 provides guidance on the factors the Commission will consider
when determining whether proposed Reliability Standards meet the statutory criteria to
ensure that they are just, reasonable, not unduly discriminatory or preferential and in the
public interest. Each of those factors is addressed in Exhibit A.
9
See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. &
Regs. ¶ 31,242 at PP 31, 186-187, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
7
b. NERC Reliability Standards Development Procedure
NERC develops Reliability Standards in accordance with Section 300 (Reliability
Standards Development) of its Rules of Procedure and the NERC Standard Processes
Manual. 10 In its ERO Certification Order, the Commission found that NERC’s proposed
rules provide for reasonable notice and opportunity for public comment, due process,
openness, and a balance of interests in developing Reliability Standards and thus satisfies
certain of the criteria for approving Reliability Standards. The development process is
open to any person or entity with a legitimate interest in the reliability of the bulk power
system. NERC considers the comments of all stakeholders, and a vote of stakeholders
and the NERC Board of Trustees is required to approve a Reliability Standard before the
Reliability Standard is submitted to the Commission for approval. The Reliability
Standards submitted herein were approved by the NERC Board of Trustees on February
9, 2012 and May 9, 2012. 11
c. History of Related Commission Orders
The Commission has addressed the issue of generator interconnection Facilities in
several fact-specific orders regarding appeals of NERC registration findings.
1. New Harquahala Generating Company, LLC
The New Harquahala decision, New Harquahala Generating Co., LLC, 123
FERC ¶ 61,173 (2008) upheld the Western Electricity Coordinating Council’s (“WECC”)
determination to register the New Harquahala Generating Company (“Harquahala”) as a
Transmission Owner and Transmission Operator based on Harquahala’s 26-mile 500 kV
10
The NERC Rules of Procedure are available here:
http://www.nerc.com/page.php?cid=1%7C8%7C169. The current NERC Standard Processes Manual is
available here: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf.
11
FAC-001-1 and PRC-004-2.1a were approved on February 9, 2012; FAC-003-3 and PRC-0051.1b were approved on May 9, 2012.
8
interconnection facilities that connect the plant with the Hassayampa transmission
substation.
2. Cedar Creek and Milford Wind
On June 16, 2011, the Commission denied the appeals of two registry decisions in
which NERC found that two entities, Cedar Creek Wind Energy, LLC (“Cedar Creek”)
and Milford Wind Corridor Phase I, LLC (“Milford”) were properly included on the
NERC Compliance Registry as Transmission Owners (“TOs”) and Transmission
Operators (“TOPs”). Cedar Creek Wind Energy, LLC et al., 135 FERC ¶ 61,141
(2011)(“June 16 Order”). In the June 16 Order, the Commission identified certain
minimum TO and TOP standards with which Milford and Cedar Creek must comply.
The Commission also suggested but did not impose a list of other relevant standards, and
ordered NERC, WECC, and the affected generators to negotiate whether to apply any
additional standards applicable to TO and TOP entities, and directed NERC to submit a
compliance filing identifying those standards. The Commission asserted there would be
reliability gaps for these two registered entities unless there were requirements imposed
for the two wind facilities that addressed: “(1) coordination of protection systems, (2)
operations and operating credentials, and (3) restoration and development and
communications of system operating limits.” 12
Requests for rehearing of certain aspects of the Commission’s order were filed by
NERC, Cedar Creek and Milford. In the order on rehearing, the Commission clarified
that it intended the following minimum list of Reliability Standards to apply to Milford
12
135 FERC ¶ 61,241 at P 63 (2011).
9
and Cedar Creek and directed NERC and WECC to determine if any additional
Reliability Standards should apply to Milford and Cedar Creek: 13
•
•
•
•
•
•
•
FAC-003-1, Requirements R1, R2;
FAC-014-2, Requirement R2;
PER-003-1, Requirements R1, R1.1, R1.2;
PRC-001-1, Requirements R2, R2.2, R4;
PRC-004-1, Requirement R1;
TOP-001, Requirement R1 and
TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4.
The Commission issued an order on November 17, 2011 denying rehearing and partially
granting clarification. 14 As in New Harquahala, the Commission ruled that its decision
was fact-specific and applied only to these two entities and that it was not making a
determination with respect to all Generator Owners and Generator Operators..
On December 2, 2011, NERC, submitted a compliance filing in response to the
June 16 Order identifying 68 requirements or sub-requirements of 12 Reliability
Standards with which Cedar Creek and Milford will comply. This compliance filing was
accepted by the Commission on June 13, 2012.15 The Commission noted that “[t]his
order does not preclude NERC from pursuing a generic approach, which NERC is
pursuing through the standards development process in Project 2010-07.” 16 The instant
filing addresses the issues considered in Project 2010-07.
d. History of Project 2010-07
13
Cedar Creek Wind Energy, LLC et al., 137 FERC ¶ 61,141 at P 29 (2011) (“In the June 16 Order,
based on the facts of those cases, we stated that Cedar Creek and Milford must comply with certain
transmission owner/operator Reliability Standards and that the negotiations that the Commission ordered
were to determine whether any additional Reliability Standards and Requirements should be applicable to
Cedar Creek and Milford.[ June 16 Order, 135 FERC ¶ 61,241 at P 72, 88].”
14
Cedar Creek Wind Energy, LLC et al., 137 FERC ¶ 61,141 (2011).
15
Cedar Creek Wind Energy, LLC et al.,139 FERC ¶ 61,214 (2012).
16
Id. at P 19.
10
As part of its work on Project 2010-07—Generator Requirements at the
Transmission Interface, the standard drafting team (“SDT”) reviewed 34 Reliability
Standards and 102 requirements to determine what changes are necessary to close a
reliability gap with respect to what is commonly known as the generator interconnection
Facility. Following the New Harquahala decision, NERC announced the formation of
the Ad Hoc Group for Generator Requirements at the Transmission Interface. The Ad
Hoc Group issued a report (“Ad Hoc Report”) that addressed many of the Reliability
Standards and requirements reviewed by the SDT.
The Ad Hoc Report proposed a solution that was based on the introduction of two
new glossary terms – Generator Interconnection Facility and Generator Interconnection
Operational Interface – and the modification of five existing NERC Glossary terms –
Transmission, Generator Owner, Generator Operator, Right-of-Way, and Vegetation
Inspection – along with companion changes to NERC’s Statement of Compliance
Registry Criteria to incorporate the changes to the definitions for Generator Owner and
Generator Operator. Following the report, a Standard Authorization Request (“SAR”)
was approved and a drafting team was formed to consider the recommendations of the Ad
Hoc Report. The Project 2010-07 drafting team carefully considered the Ad Hoc
Report’s recommendations and all industry comments submitted on the draft SAR. The
proposed definitions and definition changes that formed the basis of the Ad Hoc Report
were the subject of many industry comments. In many of the proposed standard changes,
the Ad Hoc Report simply suggested adding references to “Generator Interconnection
Facilities” to standards that were already applicable to Generator Owners or Generator
Operators. The drafting team determined that these minor insertions were not necessary
11
in the vast majority of standards, as those interconnection Facilities are inherently
accounted for in a standard where a Generator Owner or Generator Operator is an
applicable entity. The drafting team considered and settled on a more focused approach,
whereby a select number of Reliability Standards not currently applicable to generating
entities were modified.
1. Technical Justification, Review of Suggested Reliability Standards
As noted above, the drafting team reviewed and assessed the appropriate
applicability of a number of Reliability Standards, including those cited in the Ad Hoc
Report and the standards raised in the June 16 Order. The proposed modifications to
FAC-001, FAC-003, PRC-004, and PRC-005 Reliability Standards will result in the
application of certain Reliability Standards to generators without the need to register
them as Transmission Owners or Transmission Operators only as a result of sole-purpose
interconnection Facilities. This will close potential reliability gaps that exist today.
The drafting team acknowledges that some Facilities used solely to connect
generators to the transmission system are more complex and may therefore require
individual assessment. The reliability gaps associated with such Facilities should not be
addressed simply through application of all standards applicable to Transmission Owners
and Transmission Operators, but instead through an assessment of the impact of such a
Facility on neighboring transmission Facilities. Such assessment should then be used to
determine exactly which Reliability Standards and requirements should apply to that
Facility and whether additional entity registration is warranted. This assessment should,
at a minimum, be based upon the output of transmission planning and operating studies
used by the Reliability Coordinator, Transmission Operator and Transmission Planner in
12
complying with applicable Reliability Standards (specifically, IRO, TOP and TPL).The
following are evaluations of specific standards raised that are not included in this petition
and are included to provide a more complete picture of the assessments made by the
drafting team in the course of Project 2010-07.
•
EOP-003-1—Load Shedding Plans – The drafting team concluded that it was
unnecessary to extend applicability of this standard to Generator Operator entities
because PRC-001-1 already includes the requirement that Transmission Operators
coordinate their underfrequency load shedding programs (“UFLS”) with
underfrequency isolation of generating units. This coordination includes any UFLS
settings of equipment owned or operated by Generator Operators. Further, there
would be no load to shed on sole-use generator interconnection Facilities, so even if
EOP-003-1 was applied to Generator Operators, there would be no role for the
Generator Operators. In general, Generator Operators typically do not have the
technical expertise or access to the data necessary for the high-level coordination that
this standard requires, so even if the standard was applied to them, they may not be
able to execute its requirements. For these reasons, the drafting team concluded that
there was no reliability gap to address with respect to EOP-003-1.
•
EOP-005-1—System Restoration Plans –GO blackstart requirements have already
been appropriately addressed through the standards development process. EOP-0052, which was approved by the Commission in Order No. 749, will become effective
in 2013, and this standard includes system restoration requirements for Generator
Operators. 17 It would be an unnecessary use of industry and Commission resources
for the drafting team to suggest additional changes to EOP-005, when they have
already been vetted and approved by the industry and the Commission to
appropriately include Generator Operator requirements (which include generator
interconnection Facilities because Generator Operators are already responsible for
those Facilities). Even under the currently effective EOP-005-1, the Transmission
Operator is required to coordinate its restoration plan with Generator Owners and
Balancing Authorities within its area under Requirement R4.
•
FAC-014-2—Establish and Communicate System Operating Limits – The
drafting team found that this standard should not be revised to include Generator
Operators. Under the Commission-approved versions of FAC-008-1, Requirement
R1, FAC-009-1, and FAC-008-3, Requirements R1, R2, and R6 (filed for approval
with the Commission), Generator Owners are already required to document the
facility ratings for a generator interconnection circuit greater than 100kV. Those
facility ratings must respect the most limiting applicable equipment ratings in the
circuit and consider operating limitations and ambient conditions, and the ratings
17
System Restoration Reliability Standards, Order No. 749, 134 FERC ¶ 61,215 (2011), order on
clarification, Order Nos. 748-A and 749-A, 136 FERC ¶ 61,030 (2011).
13
would be conveyed by the Generator Owner to the Generator Operator if they are not
the same entity. Those voltage limits are, appropriately, set by the Transmission
Owner or Transmission Operator with which the Generator Owner or Generator
Operator interconnects. Therefore, the drafting team believes that adding the
Generator Owner to FAC-014-2, Requirement R2, would be redundant and confuse
responsibilities that are already clearly established under currently effective
standards. Further, entities with a limited view (of only their Facility) should not be
responsible for setting Interconnection Reliability Operating Limits or System
Operating Limits, as these are interconnection and system limits. The drafting team
believes this should be the responsibility of entities with a wide-area view, as shown
in the standards today.
•
IRO-005-2—Reliability Coordination – The drafting team considered the
applicability of this requirement to generator entities, but PRC-001-1, Requirement
R2, already requires the Generator Operator to notify reliability entities of relay or
equipment failures. The drafting team believes that a Special Protection System is a
form of protection system and therefore any degradation or potential failure to operate
as expected would be required to be reported by the Generator Operator to reliability
entities (Balancing Authorities, Transmission Operators, and Reliability
Coordinators). Modifying this standard would not have been necessary, but IRO005-2 was retired in October 2011 and replaced by IRO-005-3a. IRO-005-3a does
still include a requirement related to Special Protection Systems, but as with IRO005-2, Generator Operators do not need to be added to the standard because their
handling of protection systems is already addressed in PRC-001-1, Requirement R2.
IRO-005-3a will be retired when IRO-005-4 (approved by NERC’s Board of Trustees
in August 2011) is approved, and IRO-005-4 has no requirements relating to Special
Protection Systems. IRO-010-1a will then be the sole standard to cover those issues,
in Requirements R1 and R3. While those requirements do not specifically mention
Special Protection Systems, they relate to the “data specification for data and
information to building and maintain models to support Real-Time monitoring,
Operational Planning Analyses, and Real-Time Assessments.” If there are Special
Protection Systems that exist and they impact the BES, then the Reliability
Coordinator will be asking for the status and the Generator Owner or Generator
Operator will be providing it.
•
PER Standards-Operating Personnel Training – In conducting its review of all
standards that might need to apply to Generator Owners and Generator Operators, the
drafting team considered the requirements in PER-001-0, PER-002-0, and PER-0031, which the Commission has discussed in several orders.
The Commission addressed PER-001 and PER-002 in Order Nos. 693 and 742. 18 In
Order No. 693, the Commission directed NERC to expand the applicability of the
18
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693 at P 1393,
FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007);
System Personnel Training Reliability Standards, Order No. 742, 133 FERC ¶ 61,159 (2010), FERC Stats.
& Regs. ¶ 61,762 (Nov. 18, 2010), order on clarification, 134 FERC ¶ 61,078 (2011).
14
personnel training Reliability Standard, PER-002-0, to include “generator operators
centrally-located at a generation control center with a direct impact on the reliable
operation of the Bulk-Power System…” 19 In Order No. 742, the Commission
reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding
training for certain generator operator dispatch personnel, nor are we expanding a
generator operator’s responsibilities.” 20
Centrally-located generator operators working at a generation control center typically
dispatch the output from multiple generating units. As such, they can be called upon
to comply with orders from their Balancing Authority that may have a significant
impact on the reliable operation of the BES. Generator Operators who deal with
interconnection Facilities at individual generating plants, on the other hand, typically
do not receive reliability-based orders specific to the interconnection Facilities and
are therefore not covered by Order 742 and thus do not appear to be a concern of the
Commission’s. Further, the drafting team believes responsibilities are already
appropriately assigned under currently effective Reliability Standards, such as TOP001-1, Requirement R3, which requires Generator Operators to follow the directives
of the appropriate Transmission Operators, so any orders passed along from the
Balancing Authorities would be communicated by Transmission Operators to
Generator Operators under that standard.
In its June 16 order on Milford/Cedar Creek the Commission expressed concern (at
PP 67, 81) that operational control over the transmission line breakers owned by the
entities in question are not under the control of NERC certified operators, and that
PER-003-1 should thus apply to Generator Operators. The drafting team found no
evidence that the kinds of training requirements for operating the breakers of the
generator interconnection facilities cited by the Commission exist elsewhere for other
entities that operate breakers on lines. For instance, Transmission Owners that are
not also Transmission Operators are not required to undergo any sort of training.
•
PRC-001-1—System Protection Coordination – The drafting team considered that
because PRC-001-1 already applies to Generator Operators, appropriate coordination
with respect to system protection is already covered under the Reliability Standard.
Requirement R2, which applies to both the Generator Operator and Transmission
Operator, uses the general terms “relay or equipment failures,” which would include
not only generator relaying, but generator interconnection relaying where the
Generator Operator has operational responsibility for the protection system (relay or
equipment). The Generator Operator is required to notify the Transmission Operator
and Host Balancing Authority in R2.1 only “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission
Operator to notify its Reliability Coordinator and affected Transmission Operators
and Balancing Authorities. Thus, applying R2.2 to a Generator Operator would be
redundant to R2.1. The drafting team believes it is appropriate to apply R2.2 only to
19
20
Order No. 693 at P 1393.
Order No. 742 at P 84 (internal citation omitted).
15
the “wide area” Transmission Operator because a failure on a sole-use generator
interconnection Facility would not reduce system reliability. Regarding Requirement
R4, the drafting team considered that a sole-use generator interconnection Facility
would not constitute a major transmission line or major interconnection with
neighboring Generator Operators, Transmission Operators, and Balancing
Authorities. The drafting team also found that Requirement R6, which requires “area”
monitoring, was more appropriate for the Transmission Operator in light of its wide
area view of the system.
PRC-001 also illustrates how the different approaches used by the Commission and
the drafting team resolved coordination of protection systems differently. The
Commission found in Cedar Creek and Milford that coordination of protection
systems would occur for each entity if they were registered as Transmission Owners
and Transmission Operators, and if PRC-001-1, R2, R2.2, R4 and R6 applied. Since
it was seeking to find what TO/TOP standards should apply to Generator Owners and
Generator Operators, the drafting team found that PRC-001-1 R2.1 already applies to
generators and that because they are required to notify their Transmission Operator,
the coordination sought in R2.2 would occur without applying R2.2 to Generator
Operator entities or registering a Generator Owner/Generator Operator as a
Transmission Owner/Transmission Operator. For R4 and R6, the drafting team
determined that a sole-use generator interconnection Facility does not constitute a
major transmission line or major interconnection with neighboring Generator
Operators, Transmission Operators, and Balancing Authorities. R6 requires “area”
monitoring that is normally performed by a Transmission Operator, not a Generator
Operator. The drafting team determined that “area” in the context of Reliability
Standards is typically comprised of numerous Facilities, possibly not owned by the
same entity, but for which there needed to be entities assigned with the responsibility
to ensure operational reliability. The Balancing Authority and Transmission Operator
bear responsibility for Facilities located in their respective areas and the Reliability
Coordinator has oversight over its area (which could include multiple Balancing
Authority and Transmission Operator areas); by this logic, there is no “area” for the
Generator Operator to monitor and PRC-001-1 could not and should not apply to
those entities except as it does already.
•
TOP-001-1—Reliability Responsibilities and Authority – TOP-001-1 ensures that
system operators have the authority to take actions to maintain BES Facilities within
operating limits. The drafting team considered that Generator Operator
responsibilities and authority are already addressed in the standard as written. The
drafting team found that TOP-001-1 gives the Transmission Operator the necessary
decision-making authority over operation of all generator Facilities up to the point of
interconnection. TOP-001-1, Requirement R1, requires Transmission Operators to
have clear responsibility and decision-making authority to “take whatever actions are
needed to ensure the reliability of its area and shall exercise specific authority to
alleviate operating emergencies.” TOP-001-1, Requirement R3, appropriately
requires the Generator Operator to comply with reliability directives issued by the
Transmission Operator “unless such actions would violate safety, equipment,
16
regulatory or statutory requirements.” These requirements effectively give the
Transmission Operator the necessary decision-making authority over operation of all
generator Facilities up to the point of interconnection. Thus, no changes to TOP-0011 are necessary to ensure the reliability of the BES. TOP-001-2, which has been
approved by NERC’s Board of Trustees, addresses Transmission Operator and
Generator Operator responsibilities in a similar way in Requirement R1.
•
TOP-004-2—Transmission Operations – TOP-004-2, Requirement R6, is
concerned with the formal policies and procedures to provide for coordination of
activities that may impact reliability. When it comes to switching a generator
interconnection Facility in and out of service, TOP-001-1, Requirement R3, already
requires Generator Operators to comply with reliability directives issued by the
Transmission Operator. TOP-002-2, Requirement R3 provides further back up with
the Generator Owner requirement to coordinate its current-day, next-day, and
seasonal operations with its Host Balancing Authority and Transmission Service
Provider, which are in turn required to coordinated with their respective Transmission
Operators. Thus, all appropriate coordination that might be proposed by applying
TOP-004-2 to Generator Operators is already addressed in other standards. TOP-0042 has been proposed for retirement under Project 2007-03—Real-time Transmission
Operations, whose standards have been approved by the NERC Board of Trustees.
Complementary standards TOP-001-1, Requirement R3 and TOP-002-2,
Requirement R3 have also been proposed for retirement, but their requirements will
be covered under proposed IRO-001-3 Requirements R2, R3, and R4 and proposed
TOP-003-2, approved MOD-001-1a Requirements R1 and R2, and approved MOD030-2 Requirement R3 (respectively).
•
TOP-006-1—Monitoring System Conditions - The drafting team asserted in its
discussions that there was no material difference between PRC-001-1, Requirement
R1 and TOP-006-1, where the former requires knowledge of the purpose and
limitations of protection system schemes applied in its area, and the latter requires
knowledge of “the appropriate technical information concerning protective relays.”
The reliability objective is thus achieved by compliance with PRC-001-1,
Requirement R1. TOP-006-1 has been proposed for retirement under Project 200703—Real-time Transmission Operations, whose standards have been approved by the
NERC Board of Trustees.
•
TOP-008-1—Response to Transmission Limit Violations - The drafting team
concluded that there is no reliability benefit to adding this requirement. TOP-001-1
R7 (“Each Transmission Operator and Generator Operator shall not remove Bulk
Electric System facilities from service if removing those Facilities would burden
neighboring systems unless…”) and its parts give the Generator Operator authority
over its facilities, which would, for the Generator Operator, include the generator
interconnection facility. If there is an outage, R7.1 requires the Generator Operator to
notify and coordinate with its interconnecting Transmission Operator, which is
required to notify the Reliability Coordinator and other affected TOPs. TOP-008-1
has been proposed for retirement under Project 2007-03—Real-time Transmission
17
Operations, whose standards have been approved by the NERC Board of Trustees.
The appropriate coordination requirements, currently addressed in TOP-001-1 R7, are
addressed in the proposed TOP-001-2 R5 and proposed TOP-003-2, R5.
IV.
JUSTIFICATION FOR APPROVAL OF THE PROPOSED RELIABILITY
STANDARDS
a. Basis and Purpose of Reliability Standards and Improvements in this
Revision
As discussed above, the proposed Reliability Standards present a comprehensive
approach to setting forth the responsibilities for the majority of Generator Owners and
Generator Operators with generator interconnection Facilities. The following paragraphs
explain the changes made and how the new standards improve reliability when compared
to the existing standards.
i.
FAC-001-1
FAC-001-0 was approved by the Commission in Order No. 693. 21 The primary
purpose of proposed FAC-001-1 is to establish Facility connection and performance
requirements for Transmission Owners and Generator Owners in order to avoid adverse
impacts on reliability.
Proposed Requirements
•
R1. The Transmission Owner shall document, maintain, and publish Facility
connection requirements to ensure compliance with NERC Reliability Standards
and applicable Regional Entity, subregional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection requirements. The
Transmission Owner’s Facility connection requirements shall address connection
requirements for:
1.1. Generation Facilities,
1.2. Transmission Facilities, and
1.3. End-user Facilities
21
Order No. 693 at P 680.
18
•
R2. Each applicable Generator Owner shall, within 45 days of having an executed
Agreement to evaluate the reliability impact of interconnecting a third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to
the interconnected Transmission systems (under FAC-002-1), document and
publish its Facility connection requirements to ensure compliance with NERC
Reliability Standards and applicable Regional Entity, subregional, Power Pool,
and individual Transmission Owner planning criteria and Facility connection
requirements.
•
R3. Each Transmission Owner and each applicable Generator Owner (in
accordance with Requirement R2) shall address the following items in its Facility
connection requirements:
3.1. Provide a written summary of its plans to achieve the required system
performance as described in Requirements R1 or R2 throughout the
planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities
and their impacts on the interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to
others (those responsible for the reliability of the
interconnected Transmission systems) as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at
point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and
emergency operating conditions.
•
R4. The Transmission Owner shall maintain and update its Facility connection
requirements as required. The Transmission Owner shall make documentation of
these requirements available to the users of the transmission system, the Regional
Entity, and ERO on request (five business days).
Requirement R1 has been modified to reflect the fact that the term “Facilities” is a
defined term. Requirement R2 is a new Requirement that is intended to apply to
19
applicable Generator Owners. Requirement R3 has been modified to apply to applicable
Generator Owners. There is the potential for a reliability gap if this standard is not
modified so that it applies to a Generator Owner if and when it executes an Agreement to
evaluate the reliability impact of interconnecting a third party Facility to its existing
generation interconnection Facility.
The intent of this modified language is to start the compliance clock when the
Generator Owner executes an Agreement to perform the reliability assessment required in
FAC-002-1. This step is expected to occur if a Generator Owner is compelled by a
regulatory body to allow such interconnection. Assuming that a regulatory body would
require a Generator Owner to evaluate such an interconnection request, the drafting team
expects the Generator Owner and the third party to execute some form of an Agreement.
The drafting team intentionally excluded a specific reference to the form of Agreement
(such as a feasibility study) in deference to stakeholder suggestions to avoid comingling
of commercial and reliability issues in Reliability Standards.
While the scenario described in the proposed FAC-001-1 may be rare, in the past
(e.g., Alta Wind I, LLC et al., 134 FERC ¶ 61,109 at P. 19 (2011) and Sky River, LLC,
134 FERC ¶ 61,064 at P. 13 (2011)), Generator Owners have received or have been
directed to execute interconnection requests for their Facilities, and it is important to
clarify the responsibilities related to such a request in NERC’s Reliability Standards.
While such regulatory action might also result in the Generator Owner being registered
for other functions, such as Transmission Owner, Transmission Planner, and/or
Transmission Service Provider, the drafting team decided the proposed revision provides
appropriate reliability coverage until any additional registration is required and ensures
20
that the standard does not impact any Generator Owner that never executes an Agreement
as described in the standard.
Generator Owners have one year to comply with proposed FAC-001-1 as detailed
in the implementation plan. One year is adequate for allowing Generator Owners with
one or more in-place, executed interconnection Agreements to become compliant. Any
Generator Owner that executes an Agreement after the standard becomes enforceable will
have one year of awareness of the potential applicability of FAC-001-1, along with fortyfive days after the execution of the Agreement, to document and publish its facility
connection requirements.
Requirement R4 has been modified to reflect the fact that the term “Facilities” is a
defined term.
ii.
FAC-003-3
The Commission approved FAC-003-1 in Order No. 693. 22 FAC-003-2 was filed
on December 21, 2011, in Docket No. RM12-4-000 and is currently pending approval.
The primary purpose of proposed FAC-003-3 is to maintain a reliable electric
transmission system by using a defense-in-depth strategy to manage vegetation located
on transmission rights of way and minimize encroachments from vegetation located
adjacent to the right of way, thus preventing the risk of those vegetation-related outages
that could lead to Cascading.
Proposed Requirements 23
•
22
23
R1. Each applicable Transmission Owner and applicable Generator Owner shall
manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) which are either an element of an IROL, or an element of a Major WECC
Order No. 693 at P 735.
Internal references omitted.
21
Transfer Path; operating within their Rating and all Rated Electrical Operating
Conditions of the types shown below:
1. An encroachment into the MVCD as shown in FAC-003-Table 2,
observed in Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from inside the ROW that caused a
vegetation-related Sustained Outage,
3. An encroachment due to the blowing together of applicable lines and
vegetation located inside the ROW that caused a vegetation-related
Sustained Outage,
4. An encroachment due to vegetation growth into the MVCD that caused
a vegetation related Sustained Outage.
•
R2. Each applicable Transmission Owner and applicable Generator Owner shall
manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) which are not either an element of an IROL, or an element of a Major
WECC Transfer Path; operating within its Rating and all Rated Electrical
Operating Conditions of the types shown below:
1. An encroachment into the MVCD, observed in Real-time, absent a
Sustained Outage,
2. An encroachment due to a fall-in from inside the ROW that caused a
vegetation-related Sustained Outage,
3. An encroachment due to blowing together of applicable lines and
vegetation located inside the ROW that caused a vegetation-related
Sustained Outage,
4. An encroachment due to vegetation growth into the line MVCD that
caused a vegetation-related Sustained Outage
Requirements R1 and R2 have been modified to apply to applicable Generator
Owners. Proposed FAC-003-3 now requires a Generator Owner with qualifying
interconnection Facilities to perform vegetation management. The current iterations of
FAC-003 are only applicable to Transmission Owners, and thus Generator Owners with
overhead lines are not currently required to perform any kind of vegetation management
on their overhead lines. Many of these lines are less than one mile long, regularly staffed
(in the sense that employees routinely walk around under the lines in the switchyard), and
the lines run over a paved surface. For these lines, it is logical that Generator Owners not
be required to perform vegetation management; there is no vegetation to manage.
22
Other generator interconnection Facilities, however, are longer than one mile and
run through areas that may be densely populated with trees and other plants. When it
comes to vegetation management, these lines should be treated as though they are
transmission lines; the risk of outages from vegetation located on a right-of-way for a
generator-owned line is similar to the risk for Transmission Owners. Thus, these lines
have been incorporated into proposed FAC-003-3 and treated the same as other
transmission lines for the purposes of vegetation management. Proposed FAC-003-3
includes exception language (4.3.1) that excludes Facilities shorter than one mile with
clear line of sight from the fenced area of the generating station switchyard to the point of
interconnection because, as discussed above, in many cases, generation Facilities are
staffed and the overhead portion is within line-of-sight or is over a paved surface. The
other applicability qualifications included for Generator Owners (4.3.1.1, 4.3.1.2, and
4.3.1.3) mimic the qualifications applied to Transmission Owners (4.2.1, 4.2.2, and
4.2.3).
There are two effective dates associated with FAC-003-3. The first gives
Generator Owners one year, as detailed in the implementation plan, to develop
documented vegetation maintenance strategies, procedures, processes, or specifications
as outlined in Requirement R3. The second effective date allows Generator Owners two
years, as detailed in the implementation plan, to comply with Requirements R1, R2, R4,
R5, R6, and R7. This second effective date gives Generator Owners sufficient time to
begin executing the maintenance strategies, procedures, processes, or specifications
documented in the first year.
23
These effective dates take into consideration that Generator Owners were not
previously required to comply with the vegetation management standard, and should be
afforded adequate time, up to two years, to do so.
iii.
PRC-004-2.1a
The Commission approved PRC-004-1 in Order No. 693. 24 On April 15, 2011,
NERC filed an interpretation of Requirements R1 and R3 of PRC-004-1 and
Requirements R1 and R2 of PRC-005-1 which was approved by the Commission on
September 26, 2011. 25
The primary purpose of proposed PRC-004-2.1a is to ensure that all transmission
and generation Protection System Misoperations affecting the reliability of the Bulk
Electric System are analyzed and mitigated. While there was no reliability gap in the
previous version of the standard, if applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator
Protection System Misoperations, exclusive of its generator interconnection Facility.
Proposed Requirements
24
25
•
R1. The Transmission Owner and any Distribution Provider that owns a
transmission Protection System shall each analyze its transmission Protection
System Misoperations and shall develop and implement a Corrective Action Plan
to avoid future Misoperations of a similar nature according to the Regional
Entity’s procedures.
•
R2. The Generator Owner shall analyze its generator and generator
interconnection Facility Protection System Misoperations, and shall develop and
implement a Corrective Action Plan to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
•
R3. The Transmission Owner, any Distribution Provider that owns a transmission
Protection System, and the Generator Owner shall each provide to its Regional
Order No. 693 at P 1467.
North American Electric Reliability Corp., 136 FERC ¶ 61,208 (2011).
24
Entity, documentation of its Misoperations analyses and Corrective Action Plans
according to the Regional Entity’s procedures.
Requirement R2 has been modified by inserting the phrase “generator
interconnection Facility.” The standard drafting team generally rejected inserting the
phrase “generator interconnection Facility” into the Requirements of Reliability
Standards because this insertion is not typically the best method by which to add clarity,
especially when generator interconnection Facilities are already the responsibility of the
Generator Owners or Generator Operators that own and operate them. However, in the
case of PRC-004-2, the specific phrasing of R2 (“The Generator Owners shall analyze its
generator Protection System Misoperations…”) could lead to confusion regarding
whether an interconnection Facility is included. Thus, the drafting team inserted
language in PRC-004-2 in order to add clarity. The change to R2 makes clear that
generator interconnection Facilities are also part of Generator Owners’ responsibility in
the context of this standard. Given the nature of these changes, no additional time for
compliance is needed and all requirements will become effective upon approval.
25
iv.
PRC-005-1.1b
The Commission approved PRC-005-1 in Order No. 693. 26 On April 15, 2011,
NERC filed an interpretation of Requirements R1 and R3 of PRC-004-1 and
Requirements R1 and R2 of PRC-005-1 which was approved by the Commission on
September 26, 2011. 27 The primary purpose of proposed PRC-005-1.1b is to ensure that
all transmission and generation Protection Systems affecting the reliability of the Bulk
Electric System are maintained and tested.
Proposed Requirements
•
R1. Each Transmission Owner and any Distribution Provider that owns a
transmission Protection System and each Generator Owner that owns a generation
or generator interconnection Facility Protection System shall have a Protection
System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
•
R2. Each Transmission Owner and any Distribution Provider that owns a
transmission Protection System and each Generator Owner that owns a generation
or generator interconnection Facility Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Entity on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within
the defined intervals.
R2.2. Date each Protection System device was last tested/maintained.
The proposed changes to Requirement R1 and R2 are clarifying changes. While
there was no reliability gap in the previous version of the standard, if applied literally,
there was the possibility for the misperception that the Generator Owner was only
responsible for analyzing its generator Protection System, exclusive of its generator
26
27
Order No. 693 at P 1474.
North American Electric Reliability Corp., 136 FERC ¶ 61,208 (2011).
26
interconnection Facility Protection System. The changes to R1 and R2 make clear that
generator interconnection Facilities are also part of Generator Owners’ responsibility in
the context of this standard. Given the nature of these changes, no additional time for
compliance is needed and all requirements will become effective upon approval.
b. Enforceability of the Proposed Reliability Standards
The proposed Reliability Standards contain measures that support each standard
requirement by clearly identifying what is required and how the requirement will be
enforced. The VSLs also provide further guidance on the way that NERC will enforce
the requirements of the standard.
i. Violation Risk Factors and Violation Severity Levels
The revisions proposed in FAC-001-1 required additional work on VRFs and
VSLs, and the proposed FAC-003-3 revisions required a minor update to VSL
assignments. The VRFs and VSLs for the proposed standards comport with NERC and
Commission guidelines related to their assignment. For a detailed review of the VRFs,
the VSLs, and the analysis of how the VRFs and VSLs were determined using these
guidelines, please see Exhibit F. Regarding the VSLs, they have been developed based
on the situations an auditor may find during a typical compliance audit.
V.
SUMMARY OF THE RELIABILITY STANDARD DEVELOPMENT
PROCEEDINGS
The development record for proposed Reliability Standards FAC-001-1, FAC003-3, PRC-004-2.1a, and PRC-005-1.1b is summarized below. Exhibit E contains the
Consideration of Comments Reports created during the development of the Reliability
Standards. Exhibit G contains the complete record of development for the standards.
27
a. SAR Development
Project 2010-07 was initiated on January 15, 2010, and revised on November 30,
2010. The SAR was initiated by the Ad Hoc Group for Generator Requirements at the
Transmission Interface to address significant industry concern regarding the application
of Transmission Owner and Transmission Operator requirements to the registration of
Generator Owners and Generator Operators as Transmission Owners and Transmission
Operators, based on the Facilities that connect the generators to the interconnected grid.
After review of comments received in response to the SAR, NERC and
Commission Staff input, and additional industry input, the drafting team produced a
White Paper, posted for comment from March 4, 2011 to April 4, 2011, that narrowed the
scope of the project to two standards. The drafting team determined that FAC-001-1 and
FAC-003-3 would move forward in the Standards Development Process for revision to
address the reliability gap for interconnection Facilities of the Generator Owner and
expectations for the Generator Operator in operating those Facilities. A majority of
commenters agreed with the premise of the White Paper that a limited number of changes
to specific standards was preferable to developing new definitions or revising existing
definitions.
b. Overview of the Standard Drafting Team
When evaluating proposed Reliability Standards, the Commission is expected to
give “due weight” to the technical expertise of the ERO. 28 The technical expertise of the
ERO is derived from the standard drafting team. For this project, the team consisted of
six industry experts with expertise in a variety of fields, including civil engineering,
electrical engineering and generator interconnection. Each individual is considered to be
28
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824o(d)(2) (2011).
28
an expert in his field. Members of this standard drafting team provided a diversity of
experience, ranging across the United States. A detailed set of biographical information
for each of the team members is included along with the SDT roster in Exhibit H.
c. The First Posting
The first drafts of FAC-001-1, FAC-003-3, and FAC-003-X 29 were posted for a
formal comment period from June 17, 2011 to July 17, 2011. Forty-three sets of
comments were received, with comments from 143 different people from approximately
100 companies representing 9 of the 10 Industry Segments. Based on comments
received, NERC made modifications to the standards including:
•
Clarifying language in FAC-001, R2 regarding activation times to document
and publish Facility connection requirements.
•
Clarifying in FAC-001, R3 that only Generator Owners applicable in
accordance with R2 are required to comply with the requirement
•
Removing the Generator Owner from R4 of FAC-001 because of redundancy
with R2.
•
Altering the half-mile length qualifier of the line in FAC-003 to one “that
extends greater than one mile beyond the fenced area of the generating station
switchyard…”
Some commenters requested that NERC include for consideration those standards and
requirements listed in the June 2011 Cedar Creek and Milford orders. NERC concluded
29
At the time of posting, FAC-003-1 was the current Commission-approved version of the standard.
However, another version of the standard, FAC-003-2, was under development in a separate standards
project (Project 2007-07) at the time of posting. Therefore, to account for two possible outcomes with the
FAC-003 standard, the drafting team chose to make changes to two different versions of the FAC-003
standard. The drafting team chose to refer to the changes made to then-currently effective standard FAC003-1 as FAC-003-X, and to changes made to the standard under development in Project 2010-07 as FAC003-3 for the purposes of this project.
29
that no additional changes were necessary to achieve the reliability goal of the project.
As a result of this posting, NERC also proposed a minor clarifying change in PRC-004-2
with no changes to the applicability of the standard.
d. The Second Posting and Initial Ballot
The second formal comment period was held from October 5, 2011 to November
18, 2011, and included a revised version of PRC-004-2.1. A technical justification
document was provided to industry along with the standards. Forty sets of comments
were received from 123 different individuals from approximately 86 companies
representing all ten of the NERC industry segments. In response to comments received,
the drafting team made minor typographical corrections and clarifications. The drafting
team also made a change to FAC-003 Part 4.3.1 to include a reference to line of sight
“Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are…” Modifications to the
standards included:
•
In FAC-001-1, the drafting team corrected a typo in the Applicability section
4.2.1 to change “within” to “with”; corrected a typo in the VSLs for R3 to
ensure that parts 3.1.1 through 3.1.16 were referenced, rather than just 3.1.1
through 3.1.6; and changed references to “Transmission System” to
“interconnected Transmission systems” to ensure consistency with the
language elsewhere in the standard and in FAC-002-1.
•
In FAC-003-X and FAC-003-3, the drafting team added a clarifying reference
to line of sight in the GO exemption in section 4.3.1. of both versions;
30
corrected a typo in 4.3.1.2 of FAC-003-3; and changed “RE” to “Regional
Entity” in 4.3.1 of FAC-003-X.
•
The drafting team also modified FAC-003-X and FAC-003-3 Part 4.3.1 to
include a reference to line of sight to clarify the exception language based on
the intent that was agreed upon by the stakeholder body.
•
In PRC-004-2.1, the drafting team added a reference to the generator
interconnection Facility to the data retention section of the standard (for
consistency with the language in R2) and corrected a typo in the Version
History.
During this balloting period, the drafting team found that standard PRC-005-1a
required wording changes with respect to generator interconnection Facilities to comport
with changes made to PRC-004-2.1. One minority issue not resolved was the drafting
team’s continuing encouragement for NERC to reexamine standards and requirements
addressed in the Commission orders on Milford and Cedar Creek. In response, NERC
expanded its technical justification document to include any standard or requirement
cited by the Commission orders on Milford and Cedar Creek.
An initial ballot was held from November 9, 2011 to November 18, 2011. FAC001-1 achieved a quorum of 88.22% and an approval of 86.94%. FAC-003-3 achieved a
quorum of 85.08% and an approval of 85.71%. FAC-003- achieved a quorum of 84.82%
and an approval of 85.31%. PRC-004-2.1 achieved a quorum of 84.29% and an approval
of 96.09%.
31
e. Third Posting, Recirculation Ballot and Appeal
A recirculation ballot of FAC-001-1, FAC-003-3, FAC-003-X, and PRC-004-2.1
was conducted from December 14, 2011 to December 23, 2011. FAC-001-1 achieved a
quorum of 88.48% and an approval of 90.10%. FAC-003-3 achieved a quorum of
87.17% and an approval of 85.38%. FAC-003-x achieved a quorum of 86.91% and an
approval of 85.03%. PRC-004-2.1 achieved a quorum of 86.65% and an approval of
96.43%.
On January 20, 2012, Exelon Corporation submitted a Level 1 appeal through the
NERC Reliability Standards Appeals Process stating that the Standard Processes Manual
had been violated in the recirculation ballot. In its appeal, Exelon contended that there
was an improperly implemented, substantive change to the FAC-003-X and FAC-003-3
standards (specifically R4.3.1) regarding “line of sight” between the successive and
recirculation ballot. After review, NERC’s Vice President of Standards and Training
determined that changes made to the standards were in fact substantive and the Standards
Development Process had been violated. As a result, the recirculation ballots for FAC003-X and FAC-003-3 were voided and the standards were remanded to the drafting
team. However, because the appeal did not concern standards FAC-001-1 and PRC-0042.1a, NERC was able to continue development of these standards for NERC Board of
Trustees approval. From January 4, 2012 to January 13, 2012, NERC conducted a nonbinding poll on FAC-001-1 VRFs and VSLs.
f. Board of Trustees Approval of FAC-001-1 and PRC-004-2.1a
The final drafts of FAC-001-1 and PRC-004-2.1a were presented to the NERC
Board of Trustees on February 9, 2012. NERC staff provided a summary of the
32
improvements made to the two standards, as well as a summary of minority issues and
associated drafting team responses. The NERC Board of Trustees approved the
standards, and NERC staff recommended that the standards be filed with applicable
regulatory authorities. NERC staff chose to await the ongoing development of the
remainder of the standards associated with Project 2010-07, and to file with applicable
regulatory authorities once the project was completed.
g. Fourth Posting – Formal Comment Period and Second Initial and
Successive Ballots
Revised Reliability Standard PRC-005-1.1a was posted for a formal comment
period from March 2, 2012 to April 16, 2012. Nineteen set of comments were received,
including comments from 65 different people from approximately thirty-eight companies
representing nine of the ten NERC industry segments. No changes were made to the
standard. An initial ballot of PRC-005-1.1a took place from April 6, 2012 to April 16,
2012, and passed with an 88.95% quorum and a 92.41% approval.
As required by NERC’s Vice President of Standards and Training and the
Standards Committee in response to Exelon Corporation’s Level 1 appeal, the proposed
FAC-003-3 and FAC-003-X were posted concurrently for a formal comment period from
March 9, 2012 to April 9, 2012. NERC received 22 sets of comments, including
comments from 83 different people from approximately 76 companies representing 9 of
10 NERC industry segments. Several minor changes were made to FAC-003-X and
FAC-003-3 in response to the comments received.
In FAC-003-X:
•
The Applicability section was reformatted to make it clear that the standard
applies on a Facility by Facility basis (as in FAC-003-3), not simply to all
33
generator interconnection Facilities owned by a Generator Owner with at least
one qualifying generator interconnection Facility.
•
In the Purpose section, Right-of-Way was capitalized because it is an
approved NERC glossary term and “North American Electric Reliability
Council” was changed to “North American Electric Reliability Corporation.”
•
Regional Entity was added back to the Applicability section of the standard.
Requirement R4 was assigned to the Regional Entity, and the Project 2010-07
did not have the authority, based on the scope outlined in its SAR, to modify
that requirement. Thus, Regional Entity remained in the Applicability section.
In all cases, Regional Entity has been spelled out rather than referred to as
“RE.”
•
New boilerplate language, recently approved by NERC legal staff, was added
to the Effective Dates section of the standard and the Implementation Plan.
In FAC-003-3:
•
A typo was found in the Severe VSL for R2; the previous reference to
“Transmission Owner” was changed to “responsible entity,” as in all other
FAC-003-3 VSLs.
•
New boilerplate language, recently approved by NERC legal staff, was added
to the Effective Dates section of the standard and the Implementation Plan.
In the Successive Ballot conducted from March 30, 2012 to April 9, 2012, FAC-003-X
achieved an 80.10% quorum and 85.01% approval, and FAC-003-3 achieved an 80.37%
quorum and 85.18% approval.
h. Fifth Posting – Recirculation Ballot
Final drafts of proposed standards FAC-003-X, FAC-003-3, and PRC-005-1.1b
were posted for a recirculation ballot from April 24, 2012 to May 3, 2012. FAC-003-x
achieved a quorum of 81.94% and an approval of 87.32%. FAC-003-3 achieved a
quorum of 81.72% and an approval of 87.34%. PRC-005-1.1a achieved a quorum of
90.44% and an approval of 93.23%.
34
i. Board of Trustees Approval of FAC-003-3 and PRC-005-1.1b
Final drafts of FAC-003-3 30 and PRC-005-1.1b were presented to the NERC
Board of Trustees on May 9, 2012. NERC staff provided a summary of the
improvements made to the standard, as well as a summary of minority issues and
associated drafting team responses. The Board of Trustees approved the standards and
recommended that they be filed with applicable regulatory authorities.
VI.
CONCLUSION
Accordingly, the proposed Reliability Standards should be approved because they
serve the important reliability goal of ensuring that responsibility for generator
interconnection Facilities is addressed the NERC Reliability Standards where necessary
requirements were either absent or unclear. Collectively, these changes address the
reliability gap regarding generator interconnection Facilities for the vast majority of
Generator Owners and Generator Operators. They achieve that goal without generally
requiring the registration of Generator Owners and Generator Operators as Transmission
Owners and Transmission Operators and reduce associated regulatory uncertainty.
Except as necessary on a fact-specific basis, these are the only standards that need to be
applied to Generator Owners and Generator Operators to ensure the appropriate inclusion
of generator interconnection Facilities in NERC’s Reliability Standards.
For the reasons set forth above, NERC respectfully requests that the
Commission:
30
Although FAC-003-X earned industry approval through the Standards Development Process,
NERC staff presented only FAC-003-3 to the NERC Board of Trustees for Approval. FAC-003-2 was filed
on December 21, 2011 and is pending before the Commission. In the case that FAC-003-2 and FAC-003-3
do not receive regulatory approval, NERC staff will present FAC-003-X to the NERC Board of Trustees
for approval and eventual regulatory filing in order to accommodate the changes made to the FAC-003
standard in Project 2010-07.
35
•
approve the proposed Reliability Standards included in Exhibit B, effective as
proposed herein;
•
approve the implementation plans included in Exhibit D;
•
approve the retirement of Reliability Standards, effective as proposed herein.
Respectfully submitted,
/s/ Stacey Tyrewala
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001
Stacey Tyrewala
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099– facsimile
holly.hawkins@nerc.net
stacey.tyrewala@nerc.net
Charles A. Berardesco
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
charles.berardesco@nerc.net
36
CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all
parties listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 30th day of July, 2012.
/s/ Stacey Tyrewala
Stacey Tyrewala
Attorney for North American Electric
Reliability Corporation
Exhibit A
Order No. 672 Criteria
EXHIBIT A
Order No. 672 Criteria
In Order No. 672, 31 the Commission identified a number of criteria it will use to
analyze Reliability Standards proposed for approval to ensure they are just, reasonable,
not unduly discriminatory or preferential, and in the public interest. The discussion
below identifies these factors and explains how the proposed Reliability Standards have
met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve that
goal. 32
The proposed standards achieve the specific reliability goal of addressing the
application of Reliability Standards to generator interconnection Facilities which will
allow entities to understand the scope of their compliance responsibilities.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to
31
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
32
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of
Bulk-Power System facilities. It may not extend beyond reliable operation of such facilities or apply to
other facilities. Such facilities include all those necessary for operating an interconnected electric energy
transmission network, or any portion of that network, including control systems. The proposed Reliability
Standard may apply to any design of planned additions or modifications of such facilities that is necessary
to provide for reliable operation. It may also apply to Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may
propose a topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed
Reliability Standard should be developed initially by persons within the electric power industry and
community with a high level of technical expertise and be based on sound technical and engineering
criteria. It should be based on actual data and lessons learned from past operating incidents, where
appropriate. The process for ERO approval of a proposed Reliability Standard should be fair and open to
all interested persons.
2
what is required and who is required to comply. 33
The proposed revisions to these Reliability Standards apply to applicable
Generator Owners and are clear and unambiguous as to what is required and who is
required to comply, in accordance with Order No. 672.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 34
The proposed Reliability Standards include clear and understandable
consequences in accordance with Order No. 672.
4. A proposed Reliability Standard must identify clear and objective criterion
or measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 35
The proposed Reliability Standards contain measures that support each
requirement by clearly identifying what is required and how the requirement will be
enforced. These measures, included below, help provide clarity regarding how the
requirements will be enforced, and ensure that the requirements will be enforced in a
clear, consistent, and non-preferential manner and without prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively
and efficiently — but do not necessarily have to reflect “best practices” without
regard to implementation cost or historical regional infrastructure design. 36
33
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user,
owner, or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System
must know what they are required to do to maintain reliability.
34
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating
a proposed Reliability Standard should be clear and understandable by those who must comply.
35
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in
compliance with a proposed Reliability Standard. It should contain or be accompanied by an objective
measure of compliance so that it can be enforced and so that enforcement can be applied in a consistent and
non-preferential manner.
36
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the
optimal method, or “best practice,” for achieving its reliability goal without regard to implementation cost
3
The proposed Reliability Standards achieve their reliability goals effectively and
efficiently in accordance with Order No. 672.
6. Proposed Reliability Standards cannot be “lowest common denominator,”
i.e., cannot reflect a compromise that does not adequately protect Bulk-Power
System reliability. Proposed Reliability Standards can consider costs to
implement for smaller entities, but not at consequences of less than excellence in
operating system reliability. 37
The proposed Reliability Standards do not reflect a “lowest common
denominator” approach. To the contrary, the proposed standards represents a significant
improvement over the previous version as described herein.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard
while not favoring one geographic area or regional model. It should take into
account regional variations in the organization and corporate structures of
transmission owners and operators, variations in generation fuel type and
ownership patterns, and regional variations in market design if these affect the
proposed Reliability Standard. 38
or historical regional infrastructure design. It should however achieve its reliability goal effectively and
efficiently.
37
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice —
the so-called “lowest common denominator” — if such practice does not adequately protect Bulk-Power
System reliability. Although FERC will give due weight to the technical expertise of the ERO, we will not
hesitate to remand a proposed Reliability Standard if we are convinced it is not adequate to protect
reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed
Reliability Standard. However, the ERO should not propose a “lowest common denominator” Reliability
Standard that would achieve less than excellence in operating system reliability solely to protect against
reasonable expenses for supporting this vital national infrastructure. For example, a small owner or
operator of the Bulk-Power System must bear the cost of complying with each Reliability Standard that
applies to it.
38
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or
regional model but should take into account geographic variations in grid characteristics, terrain, weather,
and other such factors; it should also take into account regional variations in the organizational and
corporate structures of transmission owners and operators, variations in generation fuel type and ownership
patterns, and regional variations in market design if these affect the proposed Reliability Standard.
4
The proposed Reliability Standards apply throughout North America and do not
favor one geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 39
The proposed Reliability Standards do not restrict the available transmission
capability or limit use of the bulk-power system in a preferential manner.
9. The implementation time for the proposed Reliability Standard is
reasonable. 40
The proposed effective dates for the standards are just and reasonable and
appropriately balance the urgency in the need to implement the standards against the
reasonableness of the time allowed for those who must comply to develop necessary
procedures, software, facilities, staffing or other relevant capability.
This will allow applicable entities adequate time to ensure compliance with the
requirements. The proposed effective dates are explained in the proposed
Implementation Plans, attached as Exhibit D.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 41
39
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a
proposed Reliability Standard that has no undue negative effect on competition. Among other possible
considerations, a proposed Reliability Standard should not unreasonably restrict available transmission
capability on the Bulk-Power System beyond any restriction necessary for reliability and should not limit
use of the Bulk-Power System in an unduly preferential manner. It should not create an undue advantage
for one competitor over another.
40
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the
proposal balances any urgency in the need to implement it against the reasonableness of the time allowed
for those who must comply to develop the necessary procedures, software, facilities, staffing or other
relevant capability.
41
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commissionapproved Reliability Standard development process for the development of the particular proposed
Reliability Standard in a proper manner, especially whether the process was open and fair. However, we
5
The proposed Reliability Standards were developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving
Reliability Standards. Section V, Summary of the Reliability Standard Development
Proceedings, below, details the processes followed to develop the standard (for a more
thorough review, please see the complete development history included as Exhibit G).
These processes included, among other things, multiple comment periods, preballot review periods, and balloting periods. Additionally, all drafting team meetings
were properly noticed and open to the public. The initial and recirculation ballots both
achieved a quorum and exceeded the required ballot pool approval levels.
11. NERC must explain any balancing of vital public interests in the
development of proposed Reliability Standards.42
NERC has identified no competing public interests regarding the request for
approval of this proposed Reliability Standard. No comments were received that
indicated the proposed standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 43
No other negative factors relevant to whether the proposed Reliability Standards
are just and reasonable were identified.
caution that we will not be sympathetic to arguments by interested parties that choose, for whatever reason,
not to participate in the ERO’s Reliability Standard development process if it is conducted in good faith in
accordance with the procedures approved by FERC.
42
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests,
such as environmental, social and other goals. We expect the ERO to explain any such balancing in its
application for approval of a proposed Reliability Standard.
43
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable,
we will consider the following general factors, as well as other factors that are appropriate for the particular
Reliability Standard proposed.
6
Exhibit B
Reliability Standard submitted for Approval
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Adopted by the Board of Trustees: February 9, 2012
1 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission systems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Adopted by the Board of Trustees: February 9, 2012
2 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission systems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Adopted by the Board of Trustees: February 9, 2012
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Adopted by the Board of Trustees: February 9, 2012
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
4 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
1
1
February 9,
2012
Adopted by the Board of Trustees
Adopted by the Board of Trustees: February 9, 2012
5 of 5
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
Introduction
B.A.
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish facilityFacility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
April 1, 2005
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
C.B. Requirements
R1. The Transmission Owner shall document, maintain, and publish facilityFacility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability OrganizationEntity, subregional, Power Pool, and individual Transmission Owner
planning criteria and facilityFacility connection requirements. The Transmission Owner’s
facilityFacility connection requirements shall address connection requirements for:
R1.1.1.1.
Generation facilities,Facilities,
R1.2.1.2.
Transmission facilitiesFacilities, and
R1.3.1.3.
End-user facilitiesFacilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
R2.1.3.1.
Provide a written summary of its plans to achieve the required system
performance as described abovein Requirements R1 or R2 throughout the planning
horizon:
R2.1.1.3.1.1. Procedures for coordinated joint studies of new facilitiesFacilities and
their impacts on the interconnected transmissionTransmission systems.
R2.1.2.3.1.2. Procedures for notification of new or modified facilitiesFacilities to
others (those responsible for the reliability of the interconnected
transmissionTransmission systems) as soon as feasible.
R2.1.3.3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
R2.1.4.3.1.4.
Breaker duty and surge protection.
R2.1.5.3.1.5.
System protection and coordination.
R2.1.6.3.1.6.
Metering and telecommunications.
R2.1.7.3.1.7.
Grounding and safety issues.
R2.1.8.3.1.8.
Insulation and insulation coordination.
R2.1.9.3.1.9.
Voltage, Reactive Power, and power factor control.
R2.1.10.3.1.10. Power quality impacts.
R2.1.11.3.1.11. Equipment Ratings.
R2.1.12.3.1.12. Synchronizing of facilitiesFacilities.
R2.1.13.3.1.13. Maintenance coordination.
R2.1.14.3.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15.3.1.15. Inspection requirements for existing or new facilitiesFacilities.
R2.1.16.3.1.16. Communications and procedures during normal and emergency
operating conditions.
[VRF – Medium]
R3.R4. The Transmission Owner shall maintain and update its facilityFacility connection
requirements as required. The Transmission Owner shall make documentation of these
requirements available to the users of the transmission system, the Regional Reliability
OrganizationEntity, and NERCERO on request (five business days).
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
2 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
[VRF – Medium]
D.C. Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for
inspectionEnforcement Authority) evidence that it met all the requirements stated in
Reliability Standard FAC-001-0_Requirement R1.
M2. TheEach Generator Owner that has an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used
to interconnect to the interconnected Transmission Ownersystems shall make available (to its
Compliance Monitor) for inspectionEnforcement Authority) evidence that it met all
requirements stated in Reliability Standard FAC-001-0_Requirement R2.
M3. TheEach Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Monitor) for inspectionEnforcement
Authority) evidence that it met all the requirements stated in Reliability Standard FAC-0010_R3Requirement R3.
M3.M4. The Transmission Owner shall make available (to its Compliance Enforcement
Authority) evidence that it met all the requirements stated in Requirement R4.
E.D. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
Compliance Monitor: Regional Reliability Organization.Entity
1.2.
Compliance Monitoring Period and Reset TimeframeEnforcement Processes:
On request (five business days).
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
None specified.
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
3 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
Failed to include one
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
High VSL
Severe VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
Failed to document or
maintain or publish its
Facility connection
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
F.E. Regional Differences
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
5 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
1
1
February 9,
2012
Adopted by the Board of Trustees
Adopted by NERCthe Board of Trustees: February 8, 20059, 2012
Effective Date: April 1, 2005
6 of 6
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance strategies or procedures or processes or
specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the Generator Owner becomes
effective on the first calendar day of the first calendar quarter one year after the date of the order approving the standard from
applicable regulatory authorities where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first calendar quarter one year following
Board of Trustees’ adoption or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter two years after the date of the order
approving the standard from applicable regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 become effective on the
first day of the first calendar quarter two years following Board of Trustees’ adoption or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an Interconnection Reliability
Operating Limit (IROL) or designated by the Western Electricity Coordinating Council (WECC) as an element of a Major
WECC Transfer Path, becomes subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or
WECC initially designates the line as being an element of an IROL or an element of a Major WECC Transfer Path, or 2)
January 1 of the planning year when the line is forecast to become an element of an IROL or an element of a Major WECC
Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an IROL or a Major WECC
Transfer Path which has a specified date for the removal of such designation will no longer be subject to this standard effective
on that specified date.
Page 1 of 32
FAC-003-3 — Transmission Vegetation Management
3. A line operated at 200 kV or above, currently subject to this standard which is a designated element of an IROL or a Major
WECC Transfer Path and which has a specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard becomes subject to this standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner and which was not previously
subject to this standard becomes subject to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Page 2 of 32
FAC-003-3 — Transmission Vegetation Management
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1 Transmission Owners that own Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
4.2. 1 Each overhead transmission line operated at 200kV or higher.
4.2.2 Each overhead transmission line operated below 200kV identified as an element
of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3 Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4 Each overhead transmission line identified above (4.2.1 through 4.2.3) located
outside the fenced area of the switchyard, station or substation and any portion of the
span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
4.3.1 Overhead transmission lines that (1) extend greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to the point of
interconnection with a Transmission Owner’s Facility or (2) do not have a clear line
1
2
EPAct 2005 section 1211c: “Access approvals by Federal agencies.”
Id.
Page 3 of 32
FAC-003-3 — Transmission Vegetation Management
of sight 3 from the generating station switchyard fence to the point of interconnection
with a Transmission Owner’s Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Page 4 of 32
FAC-003-3 — Transmission Vegetation Management
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
Performance-based: Requirements 1 and 2
Competency-based: Requirement 3
Page 5 of 32
FAC-003-3 — Transmission Vegetation Management
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Page 6 of 32
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within their Rating and all Rated Electrical Operating Conditions of the types
shown below 4 [Violation Risk Factor: High] [Time Horizon: Real-time]:
1.
An encroachment into the MVCD as shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage, 5
2.
An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 6
3.
An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage 7,
4.
An encroachment due to vegetation growth into the MVCD that caused a
vegetation-related Sustained Outage. 8
M1. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R1.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below 9 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage, 10
4
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s or applicable
Generator Owner’s right to exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
7
Id.
8
Id.
9
See footnote 4.
10
See footnote 5.
Page 7 of 32
FAC-003-3 — Transmission Vegetation Management
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 11
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage, 12
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage 13
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
R3. Each applicable Transmission Owner and applicable Generator
Owner shall have documented maintenance strategies or procedures
or processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that accounts for
the following:
3.1 Movement of applicable line conductors under their Rating and
all Rated Electrical Operating Conditions;
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner and applicable Generator Owner, without any
intentional time delay, shall notify the control center holding switching authority for the
associated applicable line when the applicable Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
11
See footnote 6.
12
Id.
13
Id.
Page 8 of 32
FAC-003-3 — Transmission Vegetation Management
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
R5. When a applicable Transmission Owner and applicable Generator Owner is constrained
from performing vegetation work on an applicable line operating within its Rating and
all Rated Electrical Operating Conditions, and the constraint may lead to a vegetation
encroachment into the MVCD prior to the implementation of the next annual work
plan, then the applicable Transmission Owner or applicable Generator Owner shall take
corrective action to ensure continued vegetation management to prevent encroachments
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
R6. Each applicable Transmission Owner and applicable Generator Owner shall perform a
Vegetation Inspection of 100% of its applicable transmission lines (measured in units
of choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar
year and with no more than 18 calendar months between inspections on the same
ROW 14 [Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and applicable Generator Owner shall complete
100% of its annual vegetation work plan of applicable lines to ensure no vegetation
encroachments occur within the MVCD. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made (provided
they do not allow encroachment of vegetation into the MVCD) and must be
documented. The percent completed calculation is based on the number of units
actually completed divided by the number of units in the final amended plan (measured
in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons
for modification to annual plan may include [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]:
14
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Page 9 of 32
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 15
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcement Authority.
1.2 Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
15
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Page 10 of 32
FAC-003-3 — Transmission Vegetation Management
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
Page 11 of 32
FAC-003-3 — Transmission Vegetation Management
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Page 12 of 32
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
A grow-in
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
Page 13 of 32
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
Long-Term
Planning
Real-time
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
Lower
Medium
R5
Operations
Planning
Medium
R6
Operations
Medium
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
The responsible entity
The responsible entity failed
The responsible entity failed to
The responsible entity failed to
Page 14 of 32
FAC-003-3 — Transmission Vegetation Management
Planning
R7
Operations
Planning
Medium
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Page 15 of 32
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by an applicable Transmission Owner or applicable Generator Owner from a third party
Page 16 of 32
FAC-003-3 — Transmission Vegetation Management
such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission Owner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to include Generator
Owners and to address the matter set forth in Paragraph 734 of FERC Order 693. The Order
pointed out that Transmission Owners may in some cases own more property or rights than are
needed to reliably operate transmission lines. This modified definition represents a slight but
significant departure from the strict legal definition of “right of way” in that this definition is based
on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow
the use of such vegetation widths if there were no engineering or construction standards that
referenced the width of right of way to be maintained for vegetation on a particular line but the
evidence exists in maintenance records for a width that was in fact maintained prior to this
standard becoming mandatory. Such widths may be the only information available for lines that
had limited or no vegetation easement rights and were typically maintained primarily to ensure
public safety. This standard does not require additional easement rights to be purchased to satisfy a
minimum right of way width that did not exist prior to this standard becoming mandatory.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to include Generator Owners
and to allow both maintenance inspections and vegetation inspections to be performed
concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation
and/or slow vegetation growth rates.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Page 17 of 32
FAC-003-3 — Transmission Vegetation Management
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by an applicable Transmission Owner or applicable Generator Owner or Reliability
Coordinator to protect an Interconnection may cause excessive sagging and an outage. Another
example would be ice loading beyond the line’s Rating and Rated Electrical Operating
Condition. Such vegetation-related encroachments and outages are not violations of this
standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
Page 18 of 32
FAC-003-3 — Transmission Vegetation Management
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of an applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the applicable TO or applicable GO
should use the next largest clearance distance based on the next highest nominal voltage in the
table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, an applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
Page 19 of 32
FAC-003-3 — Transmission Vegetation Management
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
Page 20 of 32
FAC-003-3 — Transmission Vegetation Management
communication system problems (for example, cellular service or two-way radio disabled),
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner or applicable Generator Owner employee who
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
Page 21 of 32
FAC-003-3 — Transmission Vegetation Management
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Page 22 of 32
FAC-003-3 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies
1,000 miles of applicable transmission lines to be completed in the applicable Transmission
Owner’s or applicable Generator Owner’s annual plan, the applicable Transmission Owner or
applicable Generator Owner will be responsible completing those identified miles. If a
applicable Transmission Owner or applicable Generator Owner makes a modification to the
annual plan that does not put the transmission system at risk of an encroachment the annual plan
may be modified. If 100 miles of the annual plan is deferred until next year the calculation to
determine what percentage was completed for the current year would be: 1000 – 100 (deferred
miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner only completed 875 of the total
1000 miles with no acceptable documentation for modification of the annual plan the calculation
for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete
then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
Page 23 of 32
FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Page 24 of 32
FAC-003-3 — Transmission Vegetation Management
16
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 16
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 17
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
16
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will
be achieved at time of vegetation maintenance.
17
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Page 25 of 32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Page 26 of 32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Page 27 of 32
FAC-003-3 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an inPage 28 of 32
FAC-003-3 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Page 29 of 32
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
Rationale:
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Applicability (section 4.2.4):
The areas excluded in 4.2.4 were excluded based on comments from industry for reasons
summarized as follows: 1) There is a very low risk from vegetation in this area. Based on an
informal survey, no TOs reported such an event. 2) Substations, switchyards, and stations have
many inspection and maintenance activities that are necessary for reliability. Those existing
process manage the threat. As such, the formal steps in this standard are not well suited for this
environment. 3) Specifically addressing the areas where the standard does and does not apply
makes the standard clearer.
Rationale for Applicability (section 4.3):
Within the text of NERC Reliability Standard FAC-003-3, “transmission line(s) and “applicable
line(s) can also refer to the generation Facilities as referenced in 4.3 and its subsections.
Rationale for R1 and R2:
Lines with the highest significance to reliability are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage vegetation which are listed in order of increasing
degrees of severity in non-compliant performance as it relates to a failure of an applicable
Transmission Owner's or applicable Generator Owner’s vegetation maintenance program:
Page 30 of 32
FAC-003-3 — Transmission Vegetation Management
1. This management failure is found by routine inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in an otherwise sound program.
2. This management failure occurs when the height and location of a side tree within the ROW is
not adequately addressed by the program.
3. This management failure occurs when side growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative of a program that is not addressing the most
fundamental dynamic of vegetation management, (i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a mechanism for a Cascade.
Rationale for R3:
The documentation provides a basis for evaluating the competency of the applicable
Transmission Owner’s or applicable Generator Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the
applicable Transmission Owner or applicable Generator Owner avoids vegetation-to-wire
conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure
Rationale for R4:
This is to ensure expeditious communication between the applicable Transmission Owner or
applicable Generator Owner and the control center when a critical situation is confirmed.
Rationale for R5:
Legal actions and other events may occur which result in constraints that prevent the applicable
Transmission Owner or applicable Generator Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at potential risk due to constraints, the intent is for the
applicable Transmission Owner and applicable Generator Owner to put interim measures in
place, rather than do nothing.
The corrective action process is not intended to address situations where a planned work
methodology cannot be performed but an alternate work methodology can be used.
Rationale for R6:
Inspections are used by applicable Transmission Owners and applicable Generator Owners to
assess the condition of the entire ROW. The information from the assessment can be used to
determine risk, determine future work and evaluate recently-completed work. This requirement
sets a minimum Vegetation Inspection frequency of once per calendar year but with no more
than 18 months between inspections on the same ROW. Based upon average growth rates across
North America and on common utility practice, this minimum frequency is reasonable.
Transmission Owners should consider local and environmental factors that could warrant more
frequent inspections.
Page 31 of 32
FAC-003-3 — Transmission Vegetation Management
Rationale for R7:
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. It allows modifications to the planned work for changing conditions,
taking into consideration anticipated growth of vegetation and all other environmental factors,
provided that those modifications do not put the transmission system at risk of a vegetation
encroachment.
Version History
Version
3
3
Date
September 29,
2011
May 9, 2012
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
Adopted by Board of Trustees
Page 32 of 32
FAC-003-23 — Transmission Vegetation Management
Effe c tive Da te s
ThisThere are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance strategies or procedures or processes or
specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the Generator Owner becomes
effective on the first calendar day of the first calendar quarter one year after the date of the order approving the standard from
applicable regulatory authorities where such explicit approval for all requirements is required. Where In those jurisdictions
where no regulatory approval is required, the standardRequirement R3 becomes effective on the first calendar day of the first
calendar quarter one year afterfollowing Board of TrusteesTrustees’ adoption. or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
Requirement
R1 – R7
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
Quebec
Saskatchewan
USA
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
TBD
(All Req.)
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter two years after the date of the order
approving the standard from applicable regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7 become effective on the
first day of the first calendar quarter two years following Board of Trustees’ adoption or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
Page 1of Trustees: November 3, 2011 of 36
Adopted by the Board
FAC-003-23 — Transmission Vegetation Management
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an Interconnection Reliability
Operating Limit (IROL) or designated by the Western Electricity Coordinating Council (WECC) as an element of a Major
WECC Transfer Path, becomes subject to this standard the latter of: 1) 12 months after the date the Planning Coordinator or
WECC initially designates the line as being an element of an IROL or an element of a Major WECC Transfer Path, or 2)
January 1 of the planning year when the line is forecast to become an element of an IROL or an element of a Major WECC
Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an IROL or a Major WECC
Transfer Path which has a specified date for the removal of such designation will no longer be subject to this standard effective
on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated element of an IROL or a Major
WECC Transfer Path and which has a specified date for the removal of such designation will be subject to Requirement R2
and no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard becomes subject to this standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner and which was not previously
subject to this standard becomes subject to this standard 12 months after the acquisition date of the line if at the time of
acquisition the line is designated by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Page 2of Trustees: November 3, 2011 of 36
Adopted by the Board
FAC-003-23 — Transmission Vegetation Management
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-23
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
4.1.1 Applicable Transmission Owners
4.1.1.1 Transmission Owners that own Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
4.2. 1.
Each overhead transmission line operated at 200kV or higher.
4.2.2.
Each overhead transmission line operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3.
Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4.
Each overhead transmission line identified above (4.2.1 through 4.2.3)
located outside the fenced area of the switchyard, station or substation and any
portion of the span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
4.3.1 Overhead transmission lines that (1) extend greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to the point of
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
Id.
Page 3 of 36
FAC-003-23 — Transmission Vegetation Management
interconnection with a Transmission Owner’s Facility or (2) do not have a clear line
of sight 3 from the generating station switchyard fence to the point of interconnection
with a Transmission Owner’s Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Page 4 of 36
FAC-003-23 — Transmission Vegetation Management
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
Page 5 of 36
FAC-003-23 — Transmission Vegetation Management
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Page 6 of 36
FAC-003-23 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within their Rating and all Rated Electrical Operating Conditions of the types
shown below 4 [Violation Risk Factor: High] [Time Horizon: Real-time]:
1.
An encroachment into the MVCD as shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage, 5
2.
An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage, 6
3.
An encroachment due to the blowing together of applicable lines and vegetation
located inside the ROW that caused a vegetation-related Sustained Outage,4 7,
4.
An encroachment due to vegetation growth into the MVCD that caused a
vegetation-related Sustained Outage.4 8
M1. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R1.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2below 9 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
4
This requirement does not apply to circumstances that are beyond the control of aan applicable Transmission
Owner or applicable Generator Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
applicable Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and
floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation,
removal, or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s
or applicable Generator Owner’s right to exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
7
Id.
8
Id.
9
See footnote 4.
Page 7 of 36
FAC-003-23 — Transmission Vegetation Management
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage,310
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage,4 11
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,4 12
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4Outage 13
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
R3. Each applicable Transmission Owner and applicable Generator
Owner shall have documented maintenance strategies or procedures
or processes or specifications it uses to prevent the encroachment of
vegetation into the MVCD of its applicable lines that accounts for
the following:
3.1 Movement of applicable line conductors under their Rating and
all Rated Electrical Operating Conditions;
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner and applicable Generator Owner, without any
intentional time delay, shall notify the control center holding switching authority for the
associated applicable line when the applicable Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
10
See footnote 5.
11
See footnote 6.
12
Id.
13
Id.
Page 8 of 36
FAC-003-23 — Transmission Vegetation Management
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
R5. When a applicable Transmission Owner and applicable Generator Owner is constrained
from performing vegetation work on an applicable line operating within its Rating and
all Rated Electrical Operating Conditions, and the constraint may lead to a vegetation
encroachment into the MVCD prior to the implementation of the next annual work
plan, then the applicable Transmission Owner or applicable Generator Owner shall take
corrective action to ensure continued vegetation management to prevent encroachments
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
R6. Each applicable Transmission Owner and applicable Generator Owner shall perform a
Vegetation Inspection of 100% of its applicable transmission lines (measured in units
of choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar
year and with no more than 18 calendar months between inspections on the same
ROW 14 [Violation Risk Factor: Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and applicable Generator Owner shall complete
100% of its annual vegetation work plan of applicable lines to ensure no vegetation
encroachments occur within the MVCD. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made (provided
they do not allow encroachment of vegetation into the MVCD) and must be
documented. The percent completed calculation is based on the number of units
actually completed divided by the number of units in the final amended plan (measured
14
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Page 9 of 36
FAC-003-23 — Transmission Vegetation Management
in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons
for modification to annual plan may include [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of aan applicable Transmission Owner
or applicable Generator Owner 15
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
Regional Entity The Regional Entity shall serve as the Compliance Enforcement
Authority unless the applicable entity is owned, operated, or controlled by the
Regional Entity. In such cases the ERO or a Regional entity approved by FERC or
other applicable governmental authority shall serve as the CEA.
For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcement Authority.
1.2 Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
15
Circumstances that are beyond the control of aan applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Page 10 of 36
FAC-003-23 — Transmission Vegetation Management
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
Page 11 of 36
FAC-003-23 — Transmission Vegetation Management
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Page 12 of 36
FAC-003-23 — Transmission Vegetation Management
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Level
Lower
N/A
R1
Real-time
Moderate
N/A
High
High
Severe
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as
an element of an IROL or
Major WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as
an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
N/A
R2
Real-time
Medium
N/A
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
A grow-in
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
Page 13 of 36
FAC-003-23 — Transmission Vegetation Management
absent a Sustained Outage.
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
N/A
R3
R4
Long-Term
Planning
Real-time
Lower
Medium
N/A
A grow-in
The Transmission
Ownerresponsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the Transmission
Owner’sresponsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
The Transmission
Ownerresponsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
Transmission
Owner’sresponsible entity’s
applicable lines. Requirement
R3, Part 3.1)
The Transmission
Ownerresponsible entity does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
Transmission
Owner’sresponsible entity’s
applicable lines.
N/A
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
Page 14 of 36
FAC-003-23 — Transmission Vegetation Management
R5
R6
R7
Operations
Planning
Operations
Planning
Operations
Planning
The Transmission
Ownerresponsible entity did
not take corrective action when
it was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
N/A
N/A
N/A
Medium
The Transmission
Ownerresponsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The Transmission
Ownerresponsible entity
failed to inspect more than 5%
up to and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission
Ownerresponsible entity failed
to inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission
Ownerresponsible entity failed
to inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The Transmission
Ownerresponsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The Transmission
Ownerresponsible entity
failed to complete more than
5% and up to and including
10% of its annual vegetation
work plan for its applicable
lines (as finally modified).
The Transmission
Ownerresponsible entity failed
to complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The Transmission
Ownerresponsible entity failed
to complete more than 15% of
its annual vegetation work plan
for its applicable lines (as
finally modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Page 15 of 36
FAC-003-23 — Transmission Vegetation Management
Page 16 of 36
FAC-003-23 — Transmission Vegetation Management
Guideline and Technical Basis
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
Page 17 of 36
FAC-003-23 — Transmission Vegetation Management
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by aan applicable Transmission Owner or applicable Generator Owner from a third
party such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by aan
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission ownerOwner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Explanation for revising the definition of ROW:
Page 18 of 36
FAC-003-23 — Transmission Vegetation Management
The current NERC glossary definition of Right of Way has been modified to include Generator
Owners and to address the matter set forth in Paragraph 734 of FERC Order 693. The Order
pointed out that Transmission Owners may in some cases own more property or rights than are
needed to reliably operate transmission lines. This modified definition represents a slight but
significant departure from the strict legal definition of “right of way” in that this definition is based
on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow
the use of such vegetation widths if there were no engineering or construction standards that
referenced the width of right of way to be maintained for vegetation on a particular line but the
evidence exists in maintenance records for a width that was in fact maintained prior to this
standard becoming mandatory. Such widths may be the only information available for lines that
had limited or no vegetation easement rights and were typically maintained primarily to ensure
public safety. This standard does not require additional easement rights to be purchased to satisfy a
minimum right of way width that did not exist prior to this standard becoming mandatory.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to include Generator Owners
and to allow both maintenance inspections and vegetation inspections to be performed
concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation
and/or slow vegetation growth rates.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Guidelines:
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
Page 19 of 36
FAC-003-23 — Transmission Vegetation Management
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by aan applicable Transmission OperatorOwner or applicable Generator Owner or
Reliability Coordinator to protect an Interconnection may cause excessive sagging and an
outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of
this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of aan applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with aan
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Page 20 of 36
FAC-003-23 — Transmission Vegetation Management
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the TOapplicable TO or applicable
GO should use the next largest clearance distance based on the next highest nominal voltage in
the table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, aan applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach aan
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
Page 21 of 36
FAC-003-23 — Transmission Vegetation Management
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Page 22 of 36
FAC-003-23 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
Page 23 of 36
FAC-003-23 — Transmission Vegetation Management
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of aan applicable Transmission Owner’sOwner or applicable Generator Owner
employee who personally identifies such a threat in the field. Confirmation could also be made
by sending out an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
Page 24 of 36
FAC-003-23 — Transmission Vegetation Management
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when a an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Page 25 of 36
FAC-003-23 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when a an applicable Transmission Owner or applicable Generator Owner
identifies 1,000 miles of applicable transmission lines to be completed in the applicable
Transmission Owner’s or applicable Generator Owner’s annual plan, the applicable
Transmission Owner or applicable Generator Owner will be responsible completing those
identified miles. If a applicable Transmission Owner or applicable Generator Owner makes a
modification to the annual plan that does not put the transmission system at risk of an
encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until
next year the calculation to determine what percentage was completed for the current year would
be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed
annual miles. If aan applicable Transmission Owner or applicable Generator Owner only
completed 875 of the total 1000 miles with no acceptable documentation for modification of the
annual plan the calculation for failure to complete the annual plan would be: 1000 – 875 = 125
miles failed to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5%
failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
Page 26 of 36
FAC-003-23 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Page 27 of 36
FAC-003-23 — Transmission Vegetation Management
16
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 16
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 17
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
16
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will
be achieved at time of vegetation maintenance.
17
Where applicable lines are operated at nominal voltages other than those listed, Thethe applicable Transmission Owner or applicable Generator Owner should
use the maximum system voltage to determine the appropriate clearance for that line.
Page 28 of 36
FAC-003-23 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Page 29 of 36
FAC-003-23 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
( DC )
Nominal
Pole to
Ground
Voltage
(kV)MVCD
meters
Over sea
level up to
500 ft
Over 500 ft
up to 1000
ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m up
to 304.8 m
(Over 304.8
m up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to 1219.2m
(Over
1219.2m up
to 1524m
(Over 1524
m up to
1828.8 m)
(Over
1828.8m up
to
2133.6m)
(Over
2133.6m up
to
2438.4m)
(Over
2438.4m up
to
2743.2m)
(Over
2743.2m up
to 3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Page 30 of 36
FAC-003-23 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an in-
Adopted by the Board of Trustees: November 3, 2011
34
FAC-003-23 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Adopted by the Board of Trustees: November 3, 2011
34
FAC-003-23 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
Rationale:
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Applicability (section 4.2.4):
The areas excluded in 4.2.4 were excluded based on comments from industry for reasons
summarized as follows: 1) There is a very low risk from vegetation in this area. Based on an
informal survey, no TOs reported such an event. 2) Substations, switchyards, and stations have
many inspection and maintenance activities that are necessary for reliability. Those existing
process manage the threat. As such, the formal steps in this standard are not well suited for this
environment. 3) NERC has a project in place to address at a later date the applicability of this
standard to Generation Owners. 43) Specifically addressing the areas where the standard does
and does not apply makes the standard clearer.
Rationale for Applicability (section 4.3):
Within the text of NERC Reliability Standard FAC-003-3, “transmission line(s) and “applicable
line(s) can also refer to the generation Facilities as referenced in 4.3 and its subsections.
Rationale for R1 and R2:
Lines with the highest significance to reliability are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage vegetation which are listed in order of increasing
degrees of severity in non-compliant performance as it relates to a failure of aan applicable
Transmission Owner's or applicable Generator Owner’s vegetation maintenance program:
Adopted by the Board of Trustees: November 3, 2011
34
FAC-003-23 — Transmission Vegetation Management
1. This management failure is found by routine inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in an otherwise sound program.
2. This management failure occurs when the height and location of a side tree within the ROW is
not adequately addressed by the program.
3. This management failure occurs when side growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative of a program that is not addressing the most
fundamental dynamic of vegetation management, (i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a mechanism for a Cascade.
Rationale for R3:
The documentation provides a basis for evaluating the competency of the applicable
Transmission Owner’s or applicable Generator Owner’s vegetation program. There may be
many acceptable approaches to maintain clearances. Any approach must demonstrate that the
applicable Transmission Owner or applicable Generator Owner avoids vegetation-to-wire
conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for an
illustration of possible conductor locations.
Rationale for R4:
This is to ensure expeditious communication between the applicable Transmission Owner or
applicable Generator Owner and the control center when a critical situation is confirmed.
Rationale for R5:
Legal actions and other events may occur which result in constraints that prevent the applicable
Transmission Owner or applicable Generator Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at potential risk due to constraints, the intent is for the
applicable Transmission Owner and applicable Generator Owner to put interim measures in
place, rather than do nothing.
The corrective action process is not intended to address situations where a planned work
methodology cannot be performed but an alternate work methodology can be used.
Rationale for R6:
Inspections are used by applicable Transmission Owners and applicable Generator Owners to
assess the condition of the entire ROW. The information from the assessment can be used to
determine risk, determine future work and evaluate recently-completed work. This requirement
sets a minimum Vegetation Inspection frequency of once per calendar year but with no more
than 18 months between inspections on the same ROW. Based upon average growth rates across
North America and on common utility practice, this minimum frequency is reasonable.
Transmission Owners should consider local and environmental factors that could warrant more
frequent inspections.
Adopted by the Board of Trustees: November 3, 2011
34
FAC-003-23 — Transmission Vegetation Management
Rationale for R7:
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. It allows modifications to the planned work for changing conditions,
taking into consideration anticipated growth of vegetation and all other environmental factors,
provided that those modifications do not put the transmission system at risk of a vegetation
encroachment.
Adopted by the Board of Trustees: November 3, 2011
34
FAC-003-23 — Transmission Vegetation Management
Version History
Version
13
Date
TBASeptember
29, 2011
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06Revision
under Project 2010-07
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
1
23
April 4, 2007
November 3,
2011May 9,
2012
4.
Added “Draft 3: November 17,
2005” to footer.Using the latest draft of
FAC-003-2 from the Project 2007-07
SDT, modified proposed definitions and
Applicability to include Generator
Owners of a certain length.
Regulatory Approval - Effective Date
Adopted by the NERC Board of Trustees
Adopted by the Board of Trustees: November 3, 2011
New
34
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1a
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity.
1 of 4
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
Modified to address Order No. 693 Directives
contained in paragraph 1469.
Revised
2
2
August 5, 2010
Adopted by NERC Board of Trustees
2 of 4
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1a
February 17, 2011
Added Appendix 1 - Interpretation regarding
Project 2009-17
applicability of standard to protection of radially interpretation
connected transformers
1a
February 17, 2011
Adopted by the Board of Trustees
1a
September 26,
2011
2a
September 26,
2011
FERC Order issued approving the interpretation
of R1 and R3 (FERC’s Order is effective as of
September 26, 2011)
Appended FERC-approved interpretation of R1
and R3 to version 2
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
2.1a
2.1a
February 9, 2012
Revision under Project
2010-07
Errata change adopted by the Board of Trustees
3 of 4
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
Appendix 1 1
Requirement Number and Text of Requirement
R1. The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Reliability Organization’s procedures developed for Reliability
Standard PRC-003 Requirement 1.
R3. The Transmission Owner, any Distribution Provider that owns a transmission Protection System,
and the Generator Owner shall each provide to its Regional Reliability Organization,
documentation of its Misoperations analyses and Corrective Action Plans according to the
Regional Reliability Organization’s procedures developed for PRC-003 R1.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-004-1 Requirements R1 and R3 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
1
When the request for interpretation was made, it was for a previous version of the standard. Although the
interpretation references a previous version of the standard, because it is still applicable in this case, it is appended to
this version of the standard.
4 of 4
Standard PRC-004-2a2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2a2.1a
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: The first day of the first calendar quarter, one year after
applicable In those jurisdictions where regulatory approval; or in is required, all requirements
become effective upon approval. In those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter one year afterall requirements become
effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1 of 5
Standard PRC-004-2a2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.1. Compliance Enforcement Authority
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
Modified to address Order No. 693 Directives
Revised
2
2 of 5
Standard PRC-004-2a2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
contained in paragraph 1469.
2
August 5, 2010
Adopted by the NERC Board of Trustees
1a
February 17, 2011
Project 2009-17
Added Appendix 1 - Interpretation regarding
applicability of standard to protection of radially interpretation
connected transformers
1a
February 17, 2011
Adopted by the NERC Board of Trustees
1a
September 26,
2011
2a
September 26,
2011
FERC Order issued approving the interpretation
of R1 and R3 (FERC’s Order is effective as of
September 26, 2011)
Appended FERC-approved interpretation of R1
and R3 to version 2
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
2.1a
2.1a
February 9, 2012
Revision under Project
2010-07
Errata change adopted by the Board of Trustees
3 of 5
Standard PRC-004-2a2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
Appendix 1 1
Requirement Number and Text of Requirement
R1. The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Reliability Organization’s procedures developed for Reliability
Standard PRC-003 Requirement 1.
R3. The Transmission Owner, any Distribution Provider that owns a transmission Protection System,
1
When the request for interpretation was made, it was for a previous version of the standard. Although the
interpretation references a previous version of the standard, because it is still applicable in this case, it is appended to
this version of the standard.
4 of 5
Standard PRC-004-2a2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
and the Generator Owner shall each provide to its Regional Reliability Organization,
documentation of its Misoperations analyses and Corrective Action Plans according to the
Regional Reliability Organization’s procedures developed for PRC-003 R1.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-004-1 Requirements R1 and R3 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
5 of 5
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Entity on request
(within 30 calendar days). The documentation of the program implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
Page 1 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
Project 2009-17
interpretation
Page 2 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
transformers
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
1.1b
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
May 9, 2012
Adopted by Board of Trustees
Page 3 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
Page 4 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 2
Requirement Number and Text of Requirement
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
Question:
1. Does R1 require a maintenance and testing program for the battery chargers for the “station batteries”
that are considered part of the Protection System?
2. Does R1 require a maintenance and testing program for auxiliary relays and sensing devices? If so,
what types of auxiliary relays and sensing devices? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of transmission line re-closing relays?
4. Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry with
relays and devices that control actions on breakers, etc., or does R1 require a program for the entire
circuit from the battery charger to the relays to circuit breakers and all associated wiring?
5. For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing program?
Response:
1. While battery chargers are vital for ensuring “station batteries” are available to support Protection
System functions, they are not identified within the definition of “Protection Systems.” Therefore,
PRC-005-1 does not require maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not include auxiliary relays; therefore,
maintenance and testing of such devices is not explicitly required. Maintenance and testing of such
devices is addressed to the degree that an entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded auxiliary relays. Maintenance and testing of
devices that respond to quantities other than electrical quantities (for example, sudden pressure
relays) are not included within Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a basis
for the way they address this item, and 3) execute the program. PRC-005-1 does not establish specific
additional requirements relative to the scope and/or methods included within the program.
5. “Associated communication systems” refer to communication systems used to convey essential
Protection System tripping logic, sometimes referred to as pilot relaying or teleprotection. Examples
include the following:
•
communications equipment involved in power-line-carrier relaying
•
communications equipment involved in various types of permissive protection system
Page 5 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
applications
•
direct transfer-trip systems
•
digital communication systems (which would include the protection system communications
functions of standard IEC 618501 as well as various proprietary systems)
Page 6 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
To be determined
B. Requirements
5.
R1. Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Reliability
OrganizationEntity on request (within 30 calendar days). The documentation of the program
implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
Page 1 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability OrganizationEntity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels of Non-Compliance(no changes)
2.1. Level 1: Documentation of the maintenance and testing program provided was
incomplete as required in R1, but records indicate maintenance and testing did occur
within the identified intervals for the portions of the program that were documented.
2.2. Level 2: Documentation of the maintenance and testing program provided was complete
as required in R1, but records indicate that maintenance and testing did not occur within
the defined intervals.
2.3. Level 3: Documentation of the maintenance and testing program provided was
incomplete, and records indicate implementation of the documented portions of the
maintenance and testing program did not occur within the identified intervals.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation,
was not provided.
Page 2 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1
February 7,
2006
Adopted by NERC Board of Trustees
1a
November 5,
2009
Interpretation of R1, R1.1, and R1.2
adopted by the NERC Board of Trustees
Project 2009-10
Interpretation
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers adopted by the NERC
Project 2009-17
Interpretationinterpretati
on
Board of Trustees (adopted and filed as 1a instead of -1b)
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
regarding applicability of standard to
protection of radially connected
transformersof R1 and R2 (FERC’s Order
Project 2009-17
Interpretation
is effective as of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order is effective as ofdated
March 14, 2012). Updated version from
1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
Revision under Project
1.1b
Page 3 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
FERC approval of PRC-005-1b.
1.1b
May 9, 2012
2010-07
Adopted by Board of Trustees
Page 4 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
Page 5 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Page 6 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 2 1
Requirement Number and Text of Requirement
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the reliability of
the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
Question #1:
Does R1 require a maintenance and testing program for the battery chargers for the “station
batteries” that are considered part of the Protection System?
Response to Question #1
While battery chargers are vital for ensuring “station batteries” are available to support
Protection System functions, they are not identified within the definition of “Protection
Systems.” Therefore, PRC-005-1 does not require maintenance and testing of battery chargers.
Question #2
Does R1 require a maintenance and testing program for auxiliary relays and sensing devices? If
so, what types of auxiliary relays and sensing devices? (i.e. transformer sudden pressure relays)
Response to Question #2
1. The existing definitionDoes R1 require a maintenance and testing program for the battery
chargers for the “station batteries” that are considered part of “the Protection System” does not
include ?
2. Does R1 require a maintenance and testing program for auxiliary relays; therefore,
maintenance and testing of such and sensing devices is not explicitly required.
Maintenance and testing of such? If so, what types of auxiliary relays and sensing devices
is addressed to the degree that an entity’s maintenance and testing
program for DC control circuits involves? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of imbedded auxiliarytransmission line re-closing
relays. Maintenance?
4. Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry with
relays and devices that control actions on breakers, etc., or does R1 require a program for the entire
circuit from the battery charger to the relays to circuit breakers and all associated wiring?
1
According to the FERC Order issued approving a modified definition of Protection System (RD11-13-000), this
interpretation will be superseded by the modified definition of Protection System when the modified definition
becomes effective. The modified definition of Protection System becomes effective on April 1, 2013.
Page 7 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
5. For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing of devices that respond to quantities
other than electrical quantities (for example, sudden pressure relays) are
not included within Requirement R1.program?
Question #3
Does R1 require maintenance and testing of transmission line re-closing relays?
Response to Question #3:
No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
Question #4
Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry
with relays and devices that control actions on breakers, etc., or does R1 require a program for
the entire circuit from the battery charger to the relays to circuit breakers and all associated
wiring?
Response to Question #4
PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a
basis for the way they address this item, and 3) execute the program. PRC-005-1 does not
establish specific additional requirements relative to the scope and/or methods included within
the program.
Question #5
For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing program?
Response to Question #5
1. While battery chargers are vital for ensuring “station batteries” are available to support Protection
System functions, they are not identified within the definition of “Protection Systems.” Therefore,
PRC-005-1 does not require maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not include auxiliary relays; therefore,
maintenance and testing of such devices is not explicitly required. Maintenance and testing of such
devices is addressed to the degree that an entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded auxiliary relays. Maintenance and testing of
devices that respond to quantities other than electrical quantities (for example, sudden pressure
relays) are not included within Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a basis
for the way they address this item, and 3) execute the program. PRC-005-1 does not establish specific
additional requirements relative to the scope and/or methods included within the program.
Page 8 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
“Associated communication systems” refer to communication systems used to convey essential
5. Protection System tripping logic, sometimes referred to as pilot relaying or teleprotection. Examples
include the following:
•
communications equipment involved in power-line-carrier relaying
•
communications equipment involved in various types of permissive protection system
applications
•
direct transfer-trip systems
•
digital communication systems (which would include the protection system communications
functions of standard IEC 618501 as well as various proprietary systems)
•
Page 9 of 9
Exhibit C
Technical Justification Resource Document
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Updated July 16, 2012
I.
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 Reliability Standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. Many of these standards and requirements had been addressed in
the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad
Hoc Report) and additional standards were reviewed as a result of discussions with NERC and FERC
staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. Given this, the SDT began efforts to address those
standards that required modification to address the majority of interconnection Facilities and
developed a more focused approach than that of the Ad Hoc Group: to propose recommendations
whereby sole-use interconnection Facilities (at or above 100 kV) that are owned and operated by
generating entities will be included in a small set of standards and requirements previously only
applicable to Transmission Owners. The SDT agrees completely with the Ad Hoc Group’s conclusion
that Generator Owners and Operators of the majority of sole-use generator interconnection Facilities
(at voltages equal to or greater than 100 kV) should not be registered as Transmission Owners and
Transmission Operators in order to maintain reliability on the Bulk Electric System (BES). From the
beginning, the SDT emphasized that a majority of generator interconnection Facilities consist of one or
two lines interconnecting with a Transmission Owner’s Facility, and the SDT believes that the majority
of these Facilities are best addressed using the focused approach outlined below.
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as “Transmission” and thus require the Generator Owner and Generator Operator for the
Facility to be classified and registered as a Transmission Owner and Transmission Operator, the SDT
does not believe this is necessary to provide an appropriate level of reliability for the BES. Just as
important, such classification and registration could actually cause a reduction in reliability. Generator
Owners and Generator Operators do not need, and in some cases may be prohibited from having, a
wide-area view and responsibility for the integrated transmission system. Requiring Generator Owners
and Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, PRC-004, and PRC005. The SDT does not believe any further modifications to standards are necessary to maintain an
appropriate level of reliability based on the revised assumption that while generator Facilities (at 100
kV and above) will be considered by some to be transmission, Generator Owners and Generator
Operators should not be registered as Transmission Owners and Transmission Operators simply as a
result of the ownership and operation of such Facilities. Because the majority of commenters support
the SDT’s current recommendation to not adopt new terms, the SDT has elected to focus on its
standard changes and not propose revisions to existing, or creation of new, glossary terms.
Project 2010-07 Technical Justification Document
2
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, PRC-004, and PRC-005 and
then provides justification for not modifying any of the additional standards and requirements it has
reviewed.
II.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that
a regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
Reliability Standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (e.g., Alta Wind I, LLC et al., 134 FERC ¶ 61,109 at P 19 (2011) and Sky River, LLC, 134 FERC ¶
61,064 at P 13 (2011)), Generator Owners have received or have been directed to execute
interconnection requests for their Facilities, and the SDT thinks it is important to clarify the
responsibilities related to such a request in NERC’s Reliability Standards. And, while the SDT
acknowledges that such regulatory action might also result in the Generator Owner being registered
for other functions, such as Transmission Owner, Transmission Planner, and/or Transmission Service
Provider, it decided the proposed revision provides appropriate reliability coverage until any additional
registration is required and does not impact any Generator Owner that never executes an Agreement
as described in the standard.
FAC-003-3—Transmission Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT
agrees with that intended exclusion in principle; as it discusses in the document titled “Technical
Justification Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT
recognizes that in many cases, generation Facilities are (1) staffed and the overhead portion is within
Project 2010-07 Technical Justification Document
3
line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported
the rationale for exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit.
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, section 4.3.1 of FAC003-3 (which addresses applicable generation Facilities) now states: “Overhead transmission lines that
(1) extend greater than one mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner’s Facility or (2) do not have a
clear line of sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility…” The SDT took into consideration all comments submitted in both
formal comment periods, and believes that this exemption now adequately addresses the reliability
impact for a majority of the Facilities, while balancing the efforts necessary to support the standard
from all entities.
PRC-004-2.1a—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2a. The SDT recognizes that generator interconnection Facilities are now widely recognized in
the industry as the responsibility of Generator Owners and Generator Operators. While the SDT
rejected other opportunities to “drop” the phrase “generator interconnection Facility” into
requirements because it is not typically the best way to add clarity, in the case of PRC-004-2a, the SDT
believes that the phrasing of R2 (“The Generator Owner shall analyze its generator Protection System
Misoperations…”) could lead to some confusion about whether an interconnection Facility is included.
Thus, the SDT proposes adding “and generator interconnection Facility” as redlined in the draft
standard. Because there is no change in applicability, and because the SDT believes that most
Generator Owners already interpret the standard in this manner, the SDT considers this proposed
changed, reflected in PRC-004-2.1a, to be a minor and not substantive change employed only to add
clarity.
PRC-005-1.1b—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 (“…and each Generator Owner that owns a generation
Protection System…”) and R2 (“…and each Generator Owner that owns a generation Protection
System…”) of PRC-005-1b requires the same explicit reference to a generator interconnection Facility
that was added in the proposed PRC-004-2.1a R2. The SDT agreed and modified both R1 and R2 to add
“and generator interconnection Facility” as redlined in the draft standard, PRC-005-1.1b.
Project 2010-07 Technical Justification Document
4
III.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order denying the registry appeals of Cedar Creek Wind Energy, LLC and Milford Wind Corridor Phase I,
LLC (135 FERC ¶ 61,241 (2011)) (June 16 FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where (i.e., the Ad Hoc Report, or the June
16 FERC Order) the standards addressed were discussed. While the FERC Orders address specific
requirements within these standards, the SDT has found it useful to address each standard as a whole.
Often, requirements within a standard, or even from standard to standard, work in concert to ensure
that there are no reliability gaps, whereas a review of a requirement in isolation might give the
impression that there is gap.
Reliability Standard
Ad Hoc Report*
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC003-2
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
PRC-004-1, PRC-0041a, or PRC-004-2a
PRC-005-1a
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
X
X
June 16
FERC Order
X
SDT Proposal
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Project 2010-07 Technical Justification Document
5
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that FERC has stated that the June 16 FERC Order is not intended to prejudge
the work of the SDT. See Cedar Creek Wind Energy, LLC et al., 137 FERC ¶ 61,141 at P 26 (2011)(“these
proceedings do not prejudge NERC’s ongoing effort.”). The SDT also acknowledges that the discussion
in the June 16 FERC Order is related to specific cases in which certain entities will actually be registered
as Transmission Owners and Transmission Operators, a process that is distinct from the SDT’s work,
which assumes that once this project is complete, Generator Owners and Generator Operators will not
be automatically registered for any other functions based solely on ownership of a sole-use generator
interconnection facility. The rest of this document provides the SDT’s technical justification for limiting
the scope of its work to FAC-001, FAC-003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary
because PRC-001-1 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
indicates that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Since there would be no load to shed on sole-use generator interconnection
Facilities, there would be no role for the Generator Operator regardless of whether the Generator
Operator is required to comply with this standard or register as a Transmission Operator for the soleuse generator interconnection Facilities. Further, Generator Operators typically do not have the
technical expertise or access to the data necessary for the high-level coordination that this standard
requires.
EOP-005-1—System Restoration Plans
The SDT considered the application of EOP-005-1 Requirements R1, R2, R5, R6, and R7 to Generator
Operators. The SDT concluded that EOP-005 does not need to be modified under Project 2010-07,
largely because EOP-005-2 has already been revised (and approved by FERC) 1 to incorporate generator
requirements, but also for the additional reasons outlined below.
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
1
See System Restoration Reliability Standards, Order No. 749, 134 FERC ¶ 61,215 (2011).
Project 2010-07 Technical Justification Document
6
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
Further, the SDT does not believe that the restoration of a single line or Facility is intended by the
purpose statement of EOP-005, which reads: “To ensure plans, procedures, and resources are available
to restore the electric system to a normal condition in the event of a partial or total shut down of the
system” (emphasis added).
In Order No. 693, at paragraph 630, FERC approved EOP-005-1 and found that the standard:
adequately addresses operating personnel training and system restoration plans to
ensure that transmission operators, balancing authorities and reliability coordinators
are prepared to restore the Interconnection following a blackout. Accordingly, the
Commission approves Reliability Standard EOP- 005-1 as mandatory and enforceable. In
addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification to EOP-005-1 through the
Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements...
FERC also specifically addressed system restoration training concerns and requirements in Order No.
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated (at P 627)
that personnel outside a control room should be trained in system restoration, but also that this should
be included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed
in NERC’s drafting of proposed PER-005-1 Reliability Standard on operator training,
we note PER-005-1 only includes Requirements on the control room personnel and not
those outside of the control room. System restoration requires the participation of not
only control room personnel but also those outside of the control room. These
include blackstart unit operators and field switching operators in situations where
SCADA capability is unavailable. As such, the Commission believes that inclusion of
periodic system restoration drills and training and review of restoration plans in a
system restoration Reliability Standard is the most effective way of achieving the
desired goal of ensuring that all participants are trained in system restoration and that
the restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackout, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Project 2010-07 Technical Justification Document
7
Pursuant to Order No. 693, NERC initiated Project 2006-03, and empowered the System Restoration
and Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT
developed Reliability Standard EOP-005-2, which includes Generator Operator requirements for
agreements and procedures related to system restoration. In Order 749, FERC approved EOP-005-2,
which included its approval of the implementation plan for EOP-005-2. 2
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators,
balancing authorities, and reliability coordinators to have a restoration plan, test the
plan, train operating personnel in the restoration plan, and have the ability to restore
the Interconnection using the plans following a blackout. In Order No. 693, the
Commission directed the ERO to develop, through the Reliability Standard development
process, a modification to EOP-005-1 that identifies time frames for training and review
of restoration plan requirements to simulate contingencies and prepare operators for
anticipated and unforeseen events . . . 3
Also, in FERC Order No. 749 (at PP 10, 17), both NERC and FERC identified the modifications to EOP-005
as “improvements” to the standard, not changes necessary to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision
and improvement from the current set of enforceable standards” and address the
Commission’s directives in Order No. 693 related to the EOP standards. NERC explains
that, among other enhancements, “[t]he proposed revisions now clearly delineate the
responsibilities of the Reliability Coordinator and Transmission Operator in the
restoration process and restoration planning.” NERC describes the proposed Reliability
Standards as providing “specific requirements for what must be in a restoration plan,
how and when it needs to be updated and approved, what needs to be provided to
operators and what training is necessary for personnel involved in restoration
processes. (internal citations omitted)
17. . . . By enhancing the rigor of the restoration planning process, the Reliability
Standards represent an improvement from the current Standards and will improve the
reliability of the Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
2
3
http://www.nerc.com/docs/standards/sar/SRBSDT_Implementation_Plan_Clean_Preballot_Review_2009March03.pdf
Order No. 749 at P 5.
Project 2010-07 Technical Justification Document
8
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the June 16 FERC
Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In paragraph 68 of the June 16 FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in question could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.” (internal citation omitted). See also June 16 FERC Order at P 84.
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable interconnecting Transmission Owner or Transmission Operator, not the
Generator Owner or Generator Operator.
Therefore, the SDT believes that adding the Generator Owner to FAC-014-2 R2 would be redundant.
Moreover, the SDT is concerned that entities with limited view (only their Facility) should not be
responsible for setting IROLs or SOLs as these are interconnection and system limits. The SDT believes
this should be the responsibility of entities with a wide-area view, as shown in the standard today;
otherwise, the SDT is concerned that reliability may be jeopardized. Commenters – including one from
the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report and
since retired…see IRO-005-3a and BOT-approved IRO-005-4)
The drafting team considered the applicability of this standard to generator entities, but PRC-001-1,
Requirement 2, already requires the Generator Operator to notify reliability entities of relay or
equipment failures. The drafting team believes that a Special Protection System is a form of protection
system and therefore any degradation or potential failure to operate as expected would be required to
be reported by the Generator Operator to reliability entities (Balancing Authorities, Transmission
Operators, and Reliability Coordinators). Modifying this standard would not have been necessary, but
IRO-005-2 was retired in October 2011 and replaced by IRO-005-3a. IRO-005-3a does still include a
requirement related to Special Protection Systems, but as with IRO-005-2, Generator Operators do not
need to be added to the standard because their handling of protection systems is already addressed in
Project 2010-07 Technical Justification Document
9
PRC-001-1, Requirement R2. IRO-005-3a will be retired when IRO-005-4 (approved by NERC’s Board of
Trustees in August 2011) is approved, and IRO-005-4 has no requirements relating to Special Protection
Systems. IRO-010-1a will then be the sole standard to cover those issues, in Requirements R1 and R3.
While those requirements do not specifically mention Special Protection Systems, they relate to the
“data specification for data and information to building and maintain models to support Real-Time
monitoring, Operational Planning Analyses, and Real-Time Assessments.” If there are Special
Protection Systems that exist and they impact the BES, then the Reliability Coordinator will be asking
for the status and the Generator Owner or Generator Operator will be providing it.
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; and PER-003-1 was
addressed in the June 16 FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT finds that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order No. 693 (at P 1393), FERC directed NERC to expand the applicability of the personnel
training Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a
generation control center with a direct impact on the reliable operation of the Bulk-Power System..." In
Order No. 742, FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive
regarding training for certain generator operator dispatch personnel, nor are we expanding a
generator operator’s responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
Project 2010-07 Technical Justification Document
10
training would be covered by proposed changes to PER-002-0 and Order No. 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order No. 693 directives
are already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-0010 is not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The June 16 FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the June 16 FERC Order, FERC expresses concern that operational control over
the transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC states (at P 67) that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT polled generator and transmission forum members and found that the vast majority have an
existing qualification process for personnel who perform switching. The team also found that although
most field personnel who actually perform the switching of an Element or Facility are not NERC
certified, they do receive authorization (either directly from a NERC certified system operator or
through an intermediary) just prior to executing the switching to take an Element or Facility out of
service or place it into service.
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the June 16 FERC Order exist elsewhere for other entities
that operate breakers on lines. For instance, Transmission Owners that are not also Transmission
Operators are not required to undergo any sort of training.
PRC-001-1—System Protection Coordination (addressed in the June 16 FERC Order)
The June 16 FERC Order addresses PRC-001-1 R2, R2.2, R4 and R6. PRC-001-R2 requires notification
and corrective action for relay or equipment failure. Requirement R4 requires coordination of
protection systems on major transmission lines and interconnections with neighboring Generator
Operators, Transmission Operators, and Balancing Authorities.
Project 2010-07 Technical Justification Document
11
In paragraphs 64 and 78 of the June 16 FERC Order, FERC expresses concern that “there is a risk of an
adverse impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”(internal citation omitted).
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying, in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility, it would be required to report
that to its interconnected Transmission Operator under R2.1. That Transmission Operator is then
required to notify its Reliability Coordinator and other affected Transmission Operators and Balancing
Authorities under R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission line or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
Project 2010-07 Technical Justification Document
12
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report and June 16
FERC Order)
The June 16 FERC Order discusses making TOP-001-1 R1 applicable to Generator Operators. With
respect to R1, paragraphs 68 and 83 of the June 16 FERC Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the Generator Operator to comply with reliability directives issued by the Transmission Operator
“unless such actions would violate safety, equipment, regulatory or statutory requirements.” These
requirements effectively give the Transmission Operator the necessary decision-making authority over
operation of all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1
are necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Project 2010-07 Technical Justification Document
13
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the Ad Hoc Report, and the June 16 FERC Order)
The Ad Hoc Report, and the June 16 FERC Order both address the application of TOP-004-2 R6 to
Generator Operators. TOP-004-2 R6 ensures formal policies and procedures are formulated to provide
for coordination of activities that may impact reliability. In paragraphs 67 and 82 of the June 16 FERC
Order, FERC talks about entities ensuring the development of coordination protection to coordinate
switching a generator interconnection Facility in and out of service, since different entities have control
over different ends of the line. FERC concludes that for the entities in question, TOP-004-2 R6 must
apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists and cites the following standards to support this
conclusion. The purpose statements of FAC-008-3 and FAC-009-1—infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” The SDT also notes that the purpose statements of IRO001-1.1 and TOP-001-1a infer that the Reliability Coordinator and the TOP are given the authority and
Project 2010-07 Technical Justification Document
14
are assigned responsibility to take appropriate actions or direct the actions of others to return the
transmission system to normal (reliable) conditions.
All appropriate coordination that might be proposed by applying TOP-004-2 to Generator Operators is
already addressed in other standards (TOP-001-1 R3, TOP-002-2 R3, FAC-008-3, and FAC-009-1). TOP004-2 has been proposed for retirement under Project 2007-03—Real-time Transmission Operations,
whose standards have been approved by the NERC Board of Trustees. Complementary standards TOP001-1 R3 and TOP-002-2 R3 have also been proposed for retirement, but their requirements will be
covered under proposed IRO-001-3 R2, R3, and R4 and proposed TOP -003-2, approved MOD-001-1a
R1 and R2, and approved MOD-030-2 R3 (respectively).
TOP-006-1/TOP-006-2—Monitoring System Conditions
The SDT considered modification to TOP-006-1 because R3 ensures technical information is provided to
the responsible personnel and R6 ensures correct and accurate data to TOP and BA. However, PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT concluded that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet that Transmission Owner’s Facility connection and system performance
requirements for metering and telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Project 2010-07 Technical Justification Document
15
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
interconnecting Transmission Operator, who, in turn, is required to notify the Reliability Coordinator
and other affected Transmission Operators.
As with TOP-004-2, the Project 2007-03 drafting team has proposed deleting all of TOP-008-1’s
requirements and retiring the standard. The appropriate coordination requirements, currently
addressed in TOP-001-1 R7, are addressed in the proposed TOP-001-2 R5 and proposed TOP-003-2 R5.
IV.
Conclusion
The SDT has concluded that the proposed modifications to FAC-001, FAC-003, PRC-004, and PRC-005
Reliability Standards will close the reliability gaps that exist for the vast majority of the sole-purpose
interconnection lines owned or operated by generating entities included in the NERC Compliance
Registry.
The SDT does, however, acknowledge that some Facilities used solely to connect generators to the
transmission system are more complex and therefore require individual assessment. The SDT has
concluded that reliability gaps associated with such Facilities should not be addressed simply through
application of all standards applicable to Transmission Owners and Transmission Operators, but
instead has concluded that an individualized assessment of the impact of such a Facility on neighboring
transmission Facilities is warranted. Such assessment should then be used to determine exactly which
Reliability Standards and requirements should apply to that Facility and whether additional entity
registration is warranted. The SDT concluded that this assessment should, at a minimum, be based
upon the output of transmission planning and operating studies used by the Reliability Coordinator,
Transmission Operator, and Transmission Planner in complying with applicable Reliability Standards
(specifically, IRO, TOP and TPL).
The SDT would like to extend its thanks to all stakeholders who have contributed to this process –
either formally or informally – and hopes that NERC and FERC will support moving this project to a
successful solution that ensures that generator interconnection Facility responsibility is appropriately
assigned under NERC’s Reliability Standards.
Project 2010-07 Technical Justification Document
16
Exhibit D
Implementation Plan for Reliability Standard submitted for Approval
Implementation Plan for FAC-001-1—Facility
Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired at midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify one existing requirement (now R3)). Therefore, this implementation plan only
identifies a compliance timeframe for Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Implementation Plan for FAC-003-3 —
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC Glossary of Terms upon approval of FAC-003-3, or the above
definition of Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at
midnight the day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has
been approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on the order in which regulatory authorities approve FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming). Once a complete
inventory is created, the Generator Owner will begin the process of gathering information for the
TVMP. In instances where the generation interconnection Facilities are owned by a partnership, a
majority or operating partner will need to obtain partnership approval to proceed with procurement of
Implementation Plan for FAC-003-3
2
a TVMP expert, and later a tree trimming crew. Typically, a request for proposal to hire a TVMP
consultant is initiated which could take several weeks in order to obtain sufficient bids (and also satisfy
Sarbanes Oxley requirements). Once all bids have been received, a contract with a TVMP consultant is
signed. At this point, the TVMP consultant and Generator Owner staff will develop the TVMP, which
needs to take into account local growth conditions, types of vegetation and other aspects required by
FAC-003. Once the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection (as required in FAC-003-3 Requirement 1), usually done using GPS,
LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-0033 Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation. On an ongoing basis, in
addition to performing inspections and clearances as required by the entity's TVMP, the Generator
Owner will need to ensure that the training and qualification requirements for the standard are met.
The entity will also need to maintain documentation of all FAC-003-3 activities for compliance period of
one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
Implementation Plan for FAC-003-3
3
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees’ adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees’ adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
Implementation Plan for FAC-003-3
4
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
5
Implementation Plan for PRC-004-2.1a—
Analyis of Transmission and Generation
Protection System Misoperations
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-004-2a will
be retired when PRC-004-2.1a becomes effective.
Compliance with Standard
The proposed change to Requirement R2 is a clarifying change. While there was no reliability gap in the
previous version of the standard, if applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection System
Misoperations, exclusive of its generator interconnection Facility. The errata change to R2 makes clear
that generator interconnection Facilities are also part of Generator Owners’ responsibility in the
context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption.
Implementation Plan for PRC-005-1.1b—
Transmission and Generation Protection
System Maintenance and Testing
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already-approved standards. PRC-005-1b
will be retired when PRC-005-1.1b becomes effective.
Compliance with Standard
The proposed changes to Requirement R1 and R2 are clarifying changes. While there was no reliability
gap in the previous version of the standard, if applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection
System, exclusive of its generator interconnection Facility Protection System. The minor changes to R1
and R2 make clear that generator interconnection Facilities are also part of Generator Owners’
responsibility in the context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
Exhibit E
Consideration of Comments
Project 2010-07
Generator Requirements at the Transmission Interface
Related Files
Status:
FAC-001-1, FAC-003-3, PRC-004-2.1a, and PRC-005-1.1b and all associated
documents were adopted by NERC’s Board of Trustees (BOT) in February and May
2012. They are pending regulatory filing.
Purpose/Industry Need:
The proposed changes to the requirements and the addition of new requirements
will add significant clarity to Generator Owners and Generator Operators regarding
their reliability standard obligations at the interface with the interconnected grid.
Draft
Action
Dates
Results
FAC-003-x
Clean | Redline to Last Posted | Redline
to Last Approved
Implementation Plan
Clean | Redline to Last Posted
FAC-003-3
Clean | Redline to Last Posted | Redline
to Last Approved
Summary>>
Implementation Plan
Clean | Redline to Last Posted
Recirculation
Ballot
Consideration of Comment Report
(FAC-003-3 and FAC-003-x - for
reference; from successive ballot that
took place March 9 - April 9, 2012)
Clean
Info>>
PRC-005-1.1b
Clean | Redline to Last Posted
Implementation Plan
Clean | Redline to Last Posted
Consideration of Comment Report
(PRC-005-1.1b for reference; from initial
ballot that took place from March 2 -
Vote>>
04/24/12
–
05/03/12
(closed)
Ballot
Results:
FAC-003-3
FAC-003-x
PRC-0051.1b
Consideration
of Comments
April 16, 2012)
Clean
Technical Justification Document
(for reference; updated from the version
posted in March 2012)
Clean | Redline
On January 20, 2012, Exelon submitted a Level 1 Appeal of the process, challenging the results of
the recirculation ballots of FAC-003-3 and FAC-003-X that concluded on Dec. 23, 2011. The NERC
Vice President of Standards and Training and then the Standards Committee's Executive Committee
reviewed the appeal and found for the appellant, determining that the modifications the SDT made
to the applicability of FAC-003-3 and FAC-003-x prior to the recirculation ballot were substantive.
Consequently the results of the recirculation ballots for FAC-003-3 and FAC-003-x have been
declared void. The SDT has made minor modifications to the standards and posted them for a
parallel formal comment period and successive ballot.
Exelon's Level 1 Appeal
NERC Vice President of Standards and Training Response
FAC-003-x
Clean| Redline to Last Posted
Successive
Ballot
Info>>
FAC-003-3
Clean | Redline to Last Posted
Info>>
3/30/12
04/09/12
(closed)
Vote>>
Full
Records:
FAC-003-x
FAC-003-3
Implementation Plans
FAC-003-x
Clean
FAC-003-3
Clean
Supporting Materials:
Unofficial Comment Form (Word)
Formal
Comment
Standards Committee Executive
Period
Committee 2/23/12 meeting minutes
(directing that Recirculation Ballot
Results be voided and work remanded to Submit
Comments>>
the SDT)
Letter from SC Chairman to Project
2010-07 SDT Chair
Technical Justification Document
(for reference; updated from the version
posted in December 2011)
Clean | Redline
03/09/12
04/09/12
(closed)
Comments
Received>>
Consideration of
Comments(6)
Consideration of Comment Report
(for reference; updated from successive
ballot that took place October 5November 18, 2011)
Clean | Redline
PRC-005-1.1a
Clean | Redline to Last Approved
Implementation Plan
Clean
Supporting Materials
Unofficial Comment Form (Word)
Initial Ballot
Updated
Info>>
Info>>
Formal
Comment
Period
Join Ballot
Pool>>
PRC-004-2.1a
Clean | Redline to Last Approved
Implementation Plan
Supporting Materials:
Technical Justification
Clean | Redline
Technical Justification for FAC-001-1
Sole-use Generator Interconnection
Facility: Diagram 1
Sole-use Generator Interconnection
Facility: Diagram 2
VRF and VSL Justification
Info>>
Full
Record>>
Vote>>
Submit
Comments>>
FAC-001-1
Clean | Redline to Last Approved
Implementation Plan
04/06/12
04/16/12
(closed)
03/02/12
04/16/12
(closed)
03/02/12
03/31/12
(closed)
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successive
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standards was
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response are
posted on this
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Consideration of
comments(1)
Consideration of Comments on Generator Requirements at the
Transmission Interface — Project 2010-07
The GOTO Drafting Team thanks all commenters who submitted comments on the proposed
SAR and modifications to several reliability standards and NERC Glossary terms associated
with the recommendations of the Generator Requirements at the Transmission Interface Ad
Hoc Group, embodied in Project 2010-07. These standards were posted for a 30-day public
comment period from February 12, 2010 through March 15, 2010. The stakeholders were
asked to provide feedback on the standards through a special Electronic Comment Form.
There were 41 sets of comments, including comments from more than 80 different people
from over 60 companies representing 7 of the 10 Industry Segments as shown in the table
on the following pages.
In this report, comments have been organized by question number. All comments may be
reviewed in their original format on the following web page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Based on stakeholder comments, along with discussions with FERC and NERC staff, the SAR
drafting team (SAR DT) made the following modifications to the SAR:
•
Gave the Standard Drafting Team (SDT) the flexibility to include additional standards
not originally identified in the Ad Hoc Task Force Report
•
With respect to new terms and modifications of definitions of terms, the SAR DT
made it clearer that the SDT can adopt proposals as indicated in the Ad Hoc Task
Force Report or modify them to address stakeholder concerns
•
Gave the SDT the option of merging the Ad Hoc Task Force’s proposed changes into
one new standard or an existing standard(s) if deemed appropriate
•
Language changes for clarity
Some commenters indicated that the SAR as written was too broad, but the SDT believes
that giving the SDT as many options as possible is advantageous. The SDT will be the team
to ultimately determine which standards should be modified.
Many commenters made specific recommendations for modifications to standards. The SAR
DT has compiled those comments for use during the next phase of this project, standard
drafting. In particular, the comments on Question 7 and its subcomponents were intended
to provide input for the SDT in the development of its implementation plan to accompany
the project as it moves forward. The most frequently cited challenges – training,
agreements, and technical details – will be considered by the SDT.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 315-439-1390 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Generator Requirements at the Transmission Interface —
Project 2010-07
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
a.
b.
c.
d.
e.
f.
g.
8.
Do you agree that there is a reliability-related need for the proposed
standards action? ............................................................................................. 9
Do you agree with the scope of the proposed standards action? .................... 15
Do you agree with the proposed NERC Glossary additions or revisions? If you
disagree with one or more of the proposed new or modified definitions, please
provide a revision that would make the definition acceptable to you. ............ 22
Do you agree with the proposed new requirements intended to add clarity
around expectations for generator owners and operators at the transmission
interface? ....................................................................................................... 30
Do you agree with the proposed modified requirements intended to add clarity
around expectations for generator owners and operators at the transmission
interface? ....................................................................................................... 39
Do you believe there are any other Transmission Owner or Transmission
Operator standards or requirements that should be applicable to the
Generator Owner or Generator Operator other than those identified? ............ 51
The next posting of the proposed revisions to these standards will include
conforming changes to the measures and compliance elements, and will
include an implementation plan. Please identify how much time you feel an
entity will need to become fully compliant with the following new/revised
requirements: ................................................................................................. 54
Each Generator Operator shall provide its operating personnel with the
responsibility and authority to implement real-time actions to ensure the
stable and reliable operation of the Generation Facility and the Generation
Interconnection Facility, and to implement directives of the Transmission
Operator and Balancing Authority. (PER-001) ................................................ 58
Each Generator Operator shall implement an initial and continuing training
program for all personnel responsible for operating the Generator
Interconnection Facility to ensure the ability to operate the equipment in a
reliable manner. (Per-002) ............................................................................. 61
The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it
interconnects to preserve Interconnection reliability. (TOP-001) .................. 64
The Transmission Operator has decision-making authority for the Generator
Interconnection Operational Interface. (TOP-001) ......................................... 67
The Generator Operator shall notify the Transmission Operator of a change in
status of the Generation Interconnection Facility. .......................................... 70
The Generator Operator shall operate the Generation Interconnection Facility
within Facility Ratings. (TOP-004).................................................................. 73
The Generator Operator shall disconnect the Generation Interconnection
Facility immediately in coordination with the Transmission Operator when
time permits or as soon as practical thereafter if an overload or other
abnormal condition threatens equipment or personnel safety. (TOP-008) ..... 76
If you have any other comments on this SAR or proposed standard revisions
and NERC Glossary modifications that you have not already provided in
response to the prior questions, please provide them here. ........................... 79
2
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Philip R. Kleckley
SERC Planning Standards Subcommittee
Additional Member
X
Additional Organization
2
3
4
X
5
6
7
Region
Ameren Services Company
SERC
1
Entergy
SERC
1
3. James Manning
North Carolina Electric Membership Corporation
SERC
3
4. Pat Huntley
SERC Reliability Corporation
SERC
10
5. Bob Jones
Southern Company Services, Inc. - Transmission
SERC
1
Guy Zito
Additional Member
10
Segment Selection
2. Charles Long
Group
9
X
1. John Sullivan
2.
8
Northeast Power Coordinating Council
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Kurtis Chong
Independent Electricity System Operator
NPCC
2
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc.
NPCC
1
3
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
7. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8. Ben Eng
New York Power Authority
NPCC
4
9. Brian Evans-Mongeon
Utility Services
NPCC
8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
12. Kathleen Goodman
ISO - New England
NPCC
2
13. David Kiguel
Hydro One Networks Inc.
NPCC
1
14. Michael R. Lombardi
Northeast Utilities
NPCC
1
15. Randy MacDonald
New Brunswick System Operator
NPCC
2
16. Greg Mason
Dynegy Generation
NPCC
5
17. Bruce Metruck
New York Power Authority
NPCC
6
18. Chris Orzel
FPL Energy/NextEra Energy
NPCC
5
19. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
20. Robert Pellegrini
The United Illuminating Company
NPCC
1
21. Saurabh Saksena
National Grid
NPCC
1
22. Michael Schiavone
National Grid
NPCC
1
23. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
3.
Group
Rick Terrill
Luminant
4.
Group
Jalal Babik
Electric Market Policy
Additional Member
X
X
Additional Organization
X
Region
Segment Selection
5
2. Mike Garton
NPCC
6
Ben Li
ISO RTO Council Standards Review
Committee
Additional Member
10
X
SERC
Group
9
X
1. Louis Slade
5.
8
X
Additional Organization
Region
Segment Selection
1. Patrick Brown
PJM
RFC
2
2. Jame Castle
NYISO
NPCC
2
4
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
3. Lourdes Estrada-Salinero
CAISO
WECC
2
4. Matt Goldberg
ISO NE
NPCC
2
5. Steve Myers
ERCOT
ERCOT
2
6. Bill Phillips
MISO
RFC
2
7. Mark Thompson
AESO
WECC
2
8. Charles Yeung
SPP
SPP
2
6.
Group
Jason L. Marshall
Midwest ISO Standards Collaborators
Additional Member
8
Additional Organization
Region
Segment Selection
CWLP
SERC
1
2. Jim Cyrulewski
JDRJC Associates, LLC
RFC
8
3. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
4. Barb Kedrowski
We Energies
RFC
3, 4, 5
5. Sam Ciccone
First Energy
RFC
1, 3, 4, 5, 6
6. Doug Hohlbaugh
First Energy
RFC
1, 3, 4, 5, 6
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
X
Additional Organization
X
X
X
X
Region
Segment Selection
1.
City of Vero Beach
FRCC
3
2.
City of New Smyrna Beach
FRCC
3
3.
Kissimmee Utility Authority
FRCC
3
4.
Lakeland Electric
FRCC
3
5.
City of Clewiston
FRCC
3
6.
Beaches Energy Services
FRCC
1
7.
Fort Pierce Utility Authority
FRCC
4
8.
Group
Denise Koehn
Additional Member
1. Jim Burns
Bonneville Power Administration
X
Additional Organization
BPA, Transmission Technical Operations
10
X
1. Steve Rose
7.
9
X
X
X
Region
WECC
Segment Selection
1
5
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
9.
Group
Richard Kafka
Pepco Holdings, Inc - Affiliates
Additional Member
X
Additional Organization
2
3
4
X
5
6
X
X
7
Region
Conectiv Energy Supply, Inc
RFC
5
2. Don Bridge
Conectiv Energy Supply, Inc
RFC
5
3. James Newton
Pepco Energy Services
RFC
5
Group
Mary Jo Cooper
First Wind
Additional Member
Additional Organization
Region
Segment Selection
NPCC
5
2. Canandaigua Power Partners, LLC
NPCC
5
3. Canandiagu Power Partners II, LLC
NPCC
5
4. Milford Wind Coordior Phase I, LLC
WECC
5
5. Stetson Wind II, LLC
NPCC
5
6. Evergreen Wind Power V, LLC
NPCC
5
Group
Kenneth D. Brown
PSEG Companies
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Jim Hebson
PSEG ER&T
NPCC
6
2. Dave Murray
PSEG Fossil
ERCOT
5
3. Jim Hubertus
PSE&G
RFC
1, 3
12.
Group
Michael Gammon
Kansas City Power & Light
Additional Member
10
X
1. First Wind O&M, LLC
11.
9
Segment Selection
1. Kara Dundas
10.
8
X
Additional Organization
X
Region
X
X
Segment Selection
1. Jim Useldinger
KCPL
SPP
1, 3, 5, 6
2. Jennifer Flandermeyer
KCPL
SPP
1, 3, 5, 6
3. Nick McCarty
KCPL
SPP
1, 3, 5, 6
4. Melinda Mangold
KCPL
SPP
1, 3, 5, 6
5. Dennis Greashaber
KCPL
SPP
1, 3, 5, 6
6. Jerry Hatfield
KCPL
SPP
1, 3, 5, 6
6
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
7. Tom Saitta
KCPL
SPP
1, 3, 5, 6
8. Harold Wyble
KCPL
SPP
1, 3, 5, 6
13.
Individual
Jack Cashin
Energy Standards Working Group
14.
Individual
Brent Ingebrigtson
E.ON U.S.
X
X
X
X
15.
Individual
Silvia Parada-Mitchell
Transmission Owner/Generation Owner
X
X
X
X
16.
Individual
Larry Rodriguez
Entegra Power Group LLC
X
X
Individual
Ken Parker
Entegra Power Group LLC, i.e., Gila River
Power and Union Power Partners
18.
Individual
Jack Stamper
Public Utility District #1 of Clark County
19.
Individual
Daniel E. Kujala
Detroit Edison Company
20.
Individual
Mark Bennett
Competitive Power Ventures, Inc.
X
21.
Individual
Sam Dwyer
AmerenUE, Power Operations Services
X
22.
Individual
Amir Hammad
Constellation Power Source Generation Inc.
X
23.
Individual
Alisha Anker
Prairie Power, Inc.
24.
Individual
Michelle D'Antuono
Ingleside Cogeneration, LP
X
25.
Individual
Katy Mirr
Sempra Generation
X
26.
Individual
Robert Ellis
Mesquite Power
X
27.
Individual
Jon Kapitz
Xcel Energy
X
17.
8
9
X
X
X
X
X
X
X
X
X
7
10
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
28.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
29.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
30.
Individual
Scott Helyer
Tenaska, Inc.
X
31.
Individual
Kevin Gillespie
El Dorado Energy LLC
X
Individual
Patti Metro
National Rural Electric Cooperative
Association (NRECA)
33.
Individual
Greg Rowland
Duke Energy
X
X
X
X
34.
Individual
James H. Sorrels, Jr.
American Electric Power
X
X
X
X
Individual
James Manning, Bob Beadle,
Doug White, and Richard McCall
North Carolina Electric Membership
Corporation
36.
Individual
Dan Rochester
Independent Electricity System Operator
37.
Individual
Jason Shaver
American Transmission Company
38.
Individual
Laura Zotter
ERCOT ISO
39.
Individual
Darcy O'Connell
California ISO
40.
Individual
Alice Murdock
Xcel Energy
X
X
X
X
41.
Individual
Marcus Lotto
Southern California Edison co.
X
X
X
X
32.
35.
X
X
7
8
9
10
X
X
X
X
X
X
X
8
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
1. Do you agree that there is a reliability-related need for the proposed standards action?
Summary Consideration: The overwhelming majority of stakeholder comments affirmed the need for this proposed standard action.
Organization
Yes or
No
E.ON U.S.
No
Question 1 Comment
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need for
auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Luminant
No
In general, Luminant agrees there is a need to address generation facilities with extended connections to the transmission
system. However, Luminant does not agree there is a reliability need for the proposed standards action as it relates to
generators connected in close proximity to the grid where the connection typically consists of a bus or short wires connection
from the high side of a generator step up transformer to the generator breaker.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Kansas City
Power & Light
No
There is a need to bring clarity to the Reliability Standards regarding the delineation of what the Generator Owner and
Generator Operator is responsible for and for definitions distinguishing between Generator Operators at Power Plants and
“Generator Operator” as the “Power System Operator” directing a fleet of generators in a balancing area. I do not believe
reliability of the interconnected grid has suffered as a result of the shortcomings of the Reliability Standards in this regard as
the electric industry has continued to operate in a responsible manner.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR. And while we respect your concern about the definition of Generator Operator versus Power System Operator, we maintain that it is outside the
scope of this SAR.
Detroit Edison
Company
No
Vegetation Inspectionchange to include any BES componentTransmission Line or Generator Interconnection Facility Rightof-Way or any other BES component to document vegetation conditions.
Response: Thank you for your comment. Based on the SAR DT’s interpretation of this comment, we believe it is outside the scope of the SAR.
9
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
AmerenUE, Power
Operations
Services
Yes
American Electric
Power
Yes
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
California ISO
Yes
Duke Energy
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
ERCOT ISO
Yes
First Wind
Yes
Question 1 Comment
10
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Florida Municipal
Power Agency
Yes
Independent
Electricity System
Operator
Yes
ISO RTO Council
Standards Review
Committee
Yes
Mesquite Power
Yes
Midwest ISO
Standards
Collaborators
Yes
National Rural
Electric
Cooperative
Association
(NRECA)
Yes
North Carolina
Electric
Membership
Corporation
Yes
Prairie Power, Inc.
Yes
PSEG Companies
Yes
Public Utility
District #1 of Clark
Yes
Question 1 Comment
11
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 1 Comment
County
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
South Carolina
Electric and Gas
Yes
Southern
California Edison
co.
Yes
Xcel Energy
Yes
Xcel Energy
Yes
Entegra Power
Group LLC
Yes
But, that action should be reasonable, provide specific detail, and be kept simple so the reliability-related objectives are
effectively understood by those operators of the GI Facilities.
Response: The SAR DT thanks you for your comment.
Energy Standards
Working Group
Yes
EPSA members, through active participation in many NERC activities including the team that prepared the report and the
attached SAR, are strong advocates of mandatory standards to protect reliability of the Grid. We also strongly agree that
there is a need for greater clarity of the responsibilities of Generator Owner/Operators and Transmission Owner/Operators at
the Generator Interconnection Interface and thus concur with the direction of this SAR that this should be achieved without
the need for Generator Owner/Operators to be included in the registry as Transmission Owner/Operators.
Response: The SAR DT thanks you for your comment.
Competitive Power
Yes
In fact, the technical analysis in the Ad Hoc Group's Report provides a valuable and useful understanding of the specific
nature and extent of reliability issues associated with generator interconnection facilities. Up to now, the need for generator
12
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Ventures, Inc.
Question 1 Comment
TO/TOP registrations has not been supported by a clear and technically sound rationale. The Report's conclusion, based
upon its comprehensive and thorough review, that there is no need for generators to be registered as TO/TOPs to address
the specific reliability issues is especially significant.
Response: The SAR DT thanks you for your comment.
Ingleside
Cogeneration, LP
Yes
Ingleside Cogeneration, LP believes that the effort by the Ad Hoc Group for Generator Requirements at the Transmission
Interface has generally succeeded in developing criteria clarifying the ownership and operational responsibilities of registered
generation and transmission entities at their point of interface. This is an important body of work which needs to result in an
end to the forced registration of Generator Owners/Operators (GO/GOP) as Transmission Owner/Operators (TO/TOP) by
Regional Entities.
Response: The SAR DT thanks you for your comment.
Pepco Holdings,
Inc - Affiliates
Yes
It is difficult to say if there is a “reliability-related need”. Most GOs operate and maintain their Generator Interconnection
Facility in the same manner as the rest of their generation facilities. It is beneficial to differentiate between the “Generation
Interconnection Facility” and the “Transmission” system so that GOs do not have to be registered as TOs.
Response: The SAR DT thanks you for your comment.
Tenaska, Inc.
Yes
Tenaska actively participates in many NERC activities, including the team that prepared the report and the attached
SAR/Draft Standards, and strongly advocates the need for reliability of the system. We also strongly agree that there is a
need for greater clarity of the responsibilities of Generator Owner/Operators and Transmission Owner/Operators at the
Generator Interconnection Interface and thus concur with the direction of this SAR that this should be achieved without the
need for Generator Owner/Operators to be included in the registry as Transmission Owner/Operators.
Response: The SAR DT thanks you for your comment.
Manitoba Hydro
Yes
With the implementation of the new Glossary Terms, this will clarify the dividing point between GO and TO.
Response: The SAR DT thanks you for your comment.
Constellation
Power Source
Yes
Yes - Defining the compliance responsibility to align more accurately with operational reality is important in managing
reliability. However, the SDT must also consider those entities that enter into a Joint Registration Organization (“JRO”) for
certain GOP reliability standards. This registration exception applies to market entities, where there has been a JRO created
13
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Generation Inc.
Yes or
No
Question 1 Comment
that delineates specific joint responsibilities, with respect to the GOP reliability standards. It is incumbent on both parties to
comply with their agreed upon respective responsibility.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT for their consideration.
14
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
2. Do you agree with the scope of the proposed standards action?
Summary Consideration: While there were a number of responses that indicated the SAR was too broad, an in-depth review of the
comments indicated that most of the concerns could be addressed by modifications to the proposed standards changes included in the Ad Hoc
Report. As a result, many of these comments will be referred to the SDT for their consideration, including final resolution of which standards need
to be modified. Based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings, the SAR
DT also elected to give the SDT the flexibility to include additional standards (now listed in the modified SAR) not identified in the Ad Hoc Report.
Organization
Yes
or No
American Electric
Power
No
Luminant
No
Question 2 Comment
Luminant believes the scope of the standards action significantly exceeds the reliability need. The scope should only extend to
Generation Interconnection Facilities of greater than one-half (½) mile in length from the property boundary of the generation
plant. This standards action should only be applied where there is a demonstrated reliability benefit. For the bulk of the
Generator Owners, the proposal creates excessive documentation and paperwork, and increases compliance risk with no
reliability benefit to the Bulk Electric System (BES).
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
California ISO
No
Adding language in several standards actually creates confusion rather than provide clarity. For example, EOP-003-1 (Load
Shedding Plans) applies in situations when there is insufficient generation or transmission, requiring load shedding to avoid risk
of uncontrolled failure of the interconnection. This function is generally accomplished through under frequency relay settings
which will drop a pre-determined amount of load to maintain generation/load balance. Involving the Generator Operator to
comply with this standard is unnecessary and may even complicate matters because the BA and the TOP will now have to
coordinate with GOPs. Other similar examples are EOP-001-0, EOP-004-1, and TOP-001-1 where adding “Generator
Interconnection Facility” does not add clarity but is rather redundant, and may create interpretation issues.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Public Utility
District #1 of Clark
No
Clark Public Utilities believes the scope of the proposed standards actions is too broad.
15
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
County
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need for
auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate.
Florida Municipal
Power Agency
No
FAC-003 should not be applicable to Generator Owners / Operators. The intent of all of the standards is to avoid an Adverse
Reliability Impact, or as the FPA Section 215(a)(4) defines “reliable operations” as: “operating the elements of the bulk-power
system within equipment and electric system thermal, voltage and stability limits so that instability, uncontrolled separation, or
cascading failures of such systems will not occur as a result of a sudden disturbance, including a cybersecurity incident, or
unanticipated failure of system elements.” Radial Facilities serving only generating plants when tripped will not threaten an
Adverse Reliability Impact or we would be hard pressed to run that generation in the first place.FMPA believes the intent of the
standard is to prevent a cascading event where, if a line trips, another line loads heavily increasing the sag of that line, which
may sag into un-cleared vegetation, causing the second line to trip, which may in turn cause heavily loading on a third line, etc.
If a line trips in the transmission network, radial Facilities from generating plants will not have their loading changed much at all
(since they are radial) and will not participate in this sort of “thermal” cascading event. Hence, there is no cause to regulate
vegetation management of radial Facilities to generating plants since the system is always planned and operated to that
potential contingency anyway and there is no danger of an Adverse Reliability Impact. Regulating vegetation management on
radial Facilities is beyond the scope of the Federal Power Act Section 215.Generator Owners / Operators are still incented to
perform adequate vegetation management without the need for regulation because any outage of the plant results in lost
opportunity costs to the plant.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Ingleside
Cogeneration, LP
No
No. Ingleside Cogeneration, LP believes there is a secondary, but equally important issue which we believe has not been fully
addressed in the proposed SAR. There can be components of the Generator Interconnection Facility located on the Generator
Owner’s property, but are maintained by the Transmission Owner. An excellent example is the relays protecting the
interconnected transmission line. Although these are usually purchased by the Generator Owner and are financially carried on
their books, in some cases the Transmission Owner performs the associated maintenance and testing. This arrangement can
16
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
make sense as the relays are protecting a transmission system and must properly interact with relays on the other side of the
transmission line through associated communications systems. This kind of arrangement can lead to a variety of interpretations
by auditors even when presented with an Interconnection Agreement specifying the ownership/maintenance arrangement. We
believe that if the responsibility to a requirement is clearly delineated in a formal document, the associated collection and
presentation of evidence of compliance is part of that responsibility - in this case the TO owning maintenance and testing of
protective relays financially owned by the GO.The Exclusion statement under Section III.c.4 of the Statement of Compliance
Registry Criteria allows for compliance responsibility to be transferred to another entity provided it registers as the appropriate
entity. In addition, we recognize that Sections 501 and 507 of the NERC Rules of Procedure allows distribution of responsibility
among two or more entities through a Joint Registration - although that process is designed for tightly connected organizations
such as joint ventures or cooperatives.
We recommend these all-or-nothing approaches be modified in the exclusion as suggested below:
A generator owner/operator will not be registered based on these criteria if responsibilities for compliance with approved
NERC reliability standards or associated requirements including reporting have been transferred by written agreement to
another entity that has registered for the appropriate function for the transferred responsibilities, such as a load-serving
entity, G&T cooperative or joint action agency as described in Sections 501 and 507 of the NERC Rules of Procedure.
"Responsibility for individual requirements applicable to the Generator Interconnection Facility including reporting can be
transferred by written agreement without a change to an entity’s registration."
Response: The SAR DT thanks you for your comment. It is outside the scope of both the SAR DT and the SDT to propose changes to the NERC Rules of
Procedure.
ISO RTO Council
Standards Review
Committee
No
Please see our comments under Q8.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Constellation
Power Source
Generation Inc.
No
Please see the comments for Question #4: Constellation agrees with the proposed new requirements in principal. However,
further clarity is needed in the requirements so that there isn’t any added confusion. Either an implementation plan or a
“frequently asked questions” document would be recommended.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
17
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Prairie Power, Inc.
No
Question 2 Comment
PPI believes the group has extended the scope too broadly from its initial intent as described in comments below.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
AmerenUE,
Power Operations
Services
No
While we agree with the overall scope of the proposed actions, there appears to be one missing critical element. What
requirement will ensure that each GO, GOP, TO and TOP agree on the specifics of implementing these new requirements for
each GIF? Has the Ad Hoc Group considered adding a requirement to mandate execution of an Agreement or Procedure
between the GO, GOP, TO and TOP to ensure minimal specific actions that would guarantee compliance with each GIF
Requirement?
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard
or an existing standard(s).
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
Competitive
Power Ventures,
Inc.
Yes
Detroit Edison
Company
Yes
Duke Energy
Yes
El Dorado Energy
LLC
Yes
Electric Market
Yes
18
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
Policy
Energy Standards
Working Group
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
ERCOT ISO
Yes
Independent
Electricity System
Operator
Yes
Kansas City
Power & Light
Yes
Manitoba Hydro
Yes
Mesquite Power
Yes
Midwest ISO
Standards
Collaborators
Yes
North Carolina
Electric
Membership
Corporation
Yes
PSEG Companies
Yes
19
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
South Carolina
Electric and Gas
Yes
Southern
California Edison
co.
Yes
Tenaska, Inc.
Yes
Entegra Power
Group LLC
Yes
Question 2 Comment
BUT, FAC-003 SHOULD BE APPLIED IN A REASONABLE MANNER. MORE DETAIL SHOULD BE PROVIDED THAN IT
WOULD APPLY FOR MORE THAN 2 SPANS. WHAT IF THERE ARE 3 SPANS, BUT ONLY A QUARTER MILE IN DISTANCE
WHICH IS TOTALLY VISIBLE FROM THE GIF. THE SDT SHOULD MAKE SOME REASONABLE CONCESSIONS FOR
THESE SITUATIONS, OR ALLOW THE GIF TO DOCUMENT THE SOUND REASONING USED IN NOT IMPLEMENTING
FAC-003 TO THE EXTENT REQUIRED BY THE EXISTING STANDARD. A REASONABLE VEGETATION MANAGEMENT
PROGRAM SHOULD BE ADEQUATE. MORE DETAIL AND SPECIFICS DESCRIBING WHAT ADEQUATE TRAINING IS FOR
PER-002.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Pepco Holdings,
Inc - Affiliates
Yes
Defining “Generator Interconnection Facility” in the glossary is a good idea. Going beyond this to specifically note this term in
so many other standards seems unnecessary since other individual devices are not noted in so many other locations. If
“Generator Interconnection Facility” is included in all other Generating Facilities, this may simplify the process.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
Yes
The proposed SAR modification set is the responsible approach to resolve gaps Generator Interconnection Facility gaps
identified by the industry. The functions required of an Owner(s) and Operator(s) of facilities used to connect generation to the
20
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
BES (Generator Interconnection Facilities) are not the same as the functions required to own and operate Transmission and
should not be considered to be the same. We commend the task force for coming up with a reasonable approach that directly
addresses reliability without requiring GO and GOPs to perform activities that have no bearing on the reliability of the BES.
Response: The SAR DT thanks you for your comment.
21
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
3. Do you agree with the proposed NERC Glossary additions or revisions? If you disagree with one or more of the
proposed new or modified definitions, please provide a revision that would make the definition acceptable to
you.
Summary Consideration: While a majority of comments did not challenge the need for the proposed new definitions, some did suggest
modifications to those new terms, as well as to some existing terms defined in the NERC Glossary of Terms. Given this, the SAR DT modified the
SAR to make it clearer that the SDT can adopt proposals as indicated in the report or modify them to address stakeholder concerns expressed in
responses to the SAR DT questionnaire.
Organization
Yes or No
Xcel Energy
Question 3 Comment
Should the definition of Generator Interface Facility indicate that no BES (or any) loads be tapped between the generator
and the GIF operational interface?
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Independent
Electricity System
Operator
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator Operator, but do not agree with the
need for the second sentence. The first sentence already states inclusion of Generator Interconnection Facility. The first
part of the second is simply a repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence. (2) Generator Interconnection
Facility: The Sole-use facilities should include those which transmit power to redial customer loads if such facilities do not
form a part of the connection to multiple transmission facilities that are subject to network power flows.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
ISO RTO Council
Standards Review
Committee
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator Operator, but do not agree with the
need for the second sentence. The first sentence already states inclusion of Generator Interconnection Facility. The first
part of the second is simply a repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Duke Energy
No
o The definitions of Generator Owner and Generator Operator should not be revised, because every Generator Owner
and Generator Operator may not own and operate a Generator Interconnection Facility, as the revised definitions imply.
The revised definition of Generator Operator also adds a coordination requirement which is more properly included in the
requirements of a standard.
o While we are sensitive to the fact that this SAR is attempting to close a reliability gap, we believe that the definition of
22
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
Generator Interconnection Facility is too broad. The Standard Drafting Team should consider limiting it to the voltages
defined for the Bulk Electric System, and other facilities as deemed critical by the Regional Entity. Also, how does the
Regional Entity deem a facility “critical”?
o The Right-of-Way (ROW) definition should spell out TO and GO. Suggested rewording: “A corridor of land on which
electric lines may be located. The Transmission Owner or Generator Owner which owns the lines may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to construct and maintain the lines.”
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Public Utility
District #1 of Clark
County
No
Clark Public Utilities believes the proposed definitions do not provide the necessary amount of guidance and clarity. The
proposed definitions and standards revisions are being considered because of the potential impacts of a 26-mile 500 kV
Generation Interconnection Facility. The proposed definition for the term “Generation Interconnection Facility” will include
the 26- mile interconnection as well as a host of other types of interconnections that should not be considered in this effort.
Clark’s generator is attached to the transmission grid by slack span (less than 100’) between the high side of the GSU
(owned by the generator)and a circuit breaker (owned and operated by the Transmission Operator) located within the
Transmission Operators switchstation. There are no operable components in the slack span. Clark believes the currently
proposed standards actions are overly broad. The definitions and applicability of these standards must be narrowed.
Clark proposes the following definition for Generator Interconnection Facility.Generator Interconnection FacilitySole-use
facility for the purpose of connecting the generating unit(s) to the transmission grid In this regard, the sole-use facility only
transmits power associated with the interconnecting generator, whether delivered to the grid or delivered to the generator
for station service or auxiliary load, or delivered to meet cogeneration load requirements. Generator Interconnection
Facilities shall not include lines that are less than or equal to two spans in length or lines that the host Transmission
Operator has agreed to include as part of the transmission system it operates.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Kansas City
Power & Light
No
I believe the intent of what has been proposed here is to define the term, “Generator Operator” to mean the Operator that
operates units directly at a power station. With that in mind, although the proposed definition is close, I believe the
interaction with the Transmission Operator only in the definition makes this confusing. Recommend consideration of the
following definition:The entity that operates generating unit(s) and the Generator Interconnection Facility and performs the
functions of supplying energy and reactive power as directed by the Balancing Authority and the Transmission Operator.
The Generator Operator may also operate the Generator Interconnection Facility and is responsible for coordinating with
the Balancing Authority and the Transmission Operator when the facility is energized or about to be energized to/deenergized from the transmission system.In addition, recommend adding the generating station property line to the defintion
for Generator Interconnection Facility for clarity:Sole-use facility that leaves generator property line for the purpose of
connecting the generating unit(s) to the transmission grid. In this regard, the sole-use facility only transmits power
23
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
associated with the interconnecting generator, whether delivered to the grid or delivered to the generator for station service
or auxiliary load, or delivered to meet cogeneration load requirements.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Electric
Power
No
It is unclear if the Generator Interconnection Facility definition only includes facilities at 100 kV or greater or those deemed
critical to the Bulk Electric System by the Regional Entity.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina
Electric
Membership
Corporation
No
NCEMC seeks clarification from the ad hoc team regarding the definition of Generation Interconnection Facility (GIF),
especially regarding the option for ownership of the GIF. The way the definition currently reads leaves the interpretation
that it might be optional for the Generator Operator to own the GIF. We are not sure that the Ad Hoc team intended this
possible conclusion, which in our opinion, could completely change the scope of this SAR (in the case where the GOP
does NOT own the GIF). If that is the intent of the Ad Hoc team or SDT, then the definition of Generator Operator should
be changed to reflect the "option" of the GOP owning the GIF versus someone else like the Transmission Owner/Operator.
Also, the second sentence of the GOP definition is not needed in our opinion since it is a requirement of the standards and
as such requirements are not usually a part of the NERC definition.
Other definitions we suggest changing are as follows:Vegetation Inspection - The systematic examination of a Right-ofWay to document vegetation conditions. The main reason for the change in definition for ROW was the proposed use of
the non-capitalized term "electric line". Since the use of that phrase sometimes means distribution lines as well as
transmission, we suggest staying with the capitalized NERC terms for better clarity.Right-of-Way (ROW) - A corridor of
land on which a Transmission Line or Generator Interconnection Facility may be located. The owner of the Transmission
Line or Generator Interconnection Facility may own the land in fee, own an easement, or have certain
franchise,prescription, or license rights to construct and maintain lines.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI agrees with the first and existing sentence of the Generator Operator definition. However, the first part of the second
sentence regarding operating the Generator Interconnection Facility is redundant with the first sentence. The second
portion of the second sentence regarding coordinating with the Transmission Operator has been established already in
TOP-001 R7.1 and TOP-003 R1.1 for the purpose of this project.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
24
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
California ISO
No
Question 3 Comment
The definition for “Generator Interconnection Facility” (GIF) is not consistent with either Conclusion #1 of the Adhoc
Group’s final report, or with “Applicability 4.5” added under FAC-003-1. Conclusion #1 mentions “Generator
Interconnecting Facilities operating at a voltage of 100 kV or greater or those deemed critical to the Bulk Electric System
by the Regional Entity...” and Applicability 4.5 mentions “Generator Interconnection Facility above 200 kV... or are
otherwise deemed critical by the Regional entity below 200 kV...”. In both these instances it appears that the Adhoc Group
is emphasizing those Generator Interconnection Facilities that are either part of the Bulk Electric System (BES) or deemed
critical by the Regional entity. Therefore, we suggest modifying the definition as follows:First sentence, after the word grid,
add “above 200 kV or otherwise deemed critical by the Regional entity below 200 kV”.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Manitoba Hydro
No
The definition for Generator Interconnection Facility does not fully include the recommendations of the Ad Hoc Group
Conclusions. The first conclusion states that the facility must be 100 KV and above and more importantly that if there is
power flows through this station that do not belong to the generators or their exclusive station loads, then this station
becomes a TO responsibility.The definition of Transmission somewhat covers the above statement, but still need
clarity.Example:Transmission - An interconnected group of lines and associated equipment in which network powerflows
through this station are associated with the movement or transfer of electric energy between points of supply and points at
which it is transformed for delivery to customers or is delivered to other electric systems. Generator Interconnection Facility
will not contain any of the above criteria.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation
Power Source
Generation Inc.
No
The term “point of interconnection” must be used in the glossary definitions of a “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface.” It is a common industry term that is widely understood, and is even
being used in the revision to FAC-008. Using the term “point of interconnection” would further clarify the new glossary
definitions. Here are the proposed changes:Generator Interconnection Facility (NEW)Sole-use facility for the purpose of
connecting the generating unit(s) to the transmission grid. In this regard, the sole-use facility only transmits power
associated with the interconnecting generator, whether delivered to the grid or delivered to the generator for station service
or auxiliary load, or delivered to meet cogeneration load requirements.The Generator Interconnection Facility is physically
defined as the facility and its encompassing equipment beginning at the low side of the Generator Step Up to the point of
interconnection. Generators connected to the same interconnection facility with different Generator Operators must
coordinate operations. Generator Interconnection Operational Interface (NEW)Location at which operating responsibility
for the Generator Interconnection Facility changes between the Transmission Operator and the Generator Operator.This
location is known as the point of interconnection.
Response: The SAR DT thanks you for your comment. Because of potential confusion with language in various interconnection agreements, the SAR DT will
25
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
not make changes to this definition and will defer to the SDT.
Midwest ISO
Standards
Collaborators
No
We agree with the first sentence of the definition of Generator Operator. However, the first part of the second sentence
regarding operating the Generator Interconnection Facility is redundant with the first sentence. The second portion of the
second sentence regarding coordinating with the Transmission Operator is a requirement and already established in
requirement X.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
No
We recommend the definition of Generator Interconnection Facility be modified.
”Generator Interconnection Facility (NEW)A facility used for the sole purpose of connecting the generating unit(s) to
the transmission grid. In this regard, the sole-use facility only transmits power associated with the interconnecting
generator(s), whether delivered to the grid or delivered to the generator(s) for station service or auxiliary load, or
delivered to meet cogeneration load requirements.
The purpose of the above modification is to account for the situations where a Generator Operator may have many units,
such as wind turbines, all using the same Generator Interconnection Facility to connect to the transmission grid.
Additionally, we feel it is irrelevant if the Generating Unit is owned by one or the same owners. Two scenarios explain why
multiple generators using the same Generator Interconnection Facility does not serve a function of a TO or TOP.
• Scenario 1Each Generator Operator is connected to the Transmission Operator through an independent Generator
Interconnection Facility. There is no need for the Generator Operators to coordinate their operations with one
another because their operations do not impact common facilities. However, there may be a need for the
Transmission Operator to coordinate its instructions to the Generator Operators (if they issue voltage schedules,
for example). When it becomes necessary for the Transmission Operator to communicate instructions to the
Generator Operators, it is necessary for the Transmission Operator to communicate with each of the Generator
Operators.
• Scenario 2Generator Operator A is connected independently, but Generator Operators B and C share a common
Generator Interconnection Facility. In this case, it is necessary for Generators B and C to coordinate their
operations. It is not necessary to designate either GO_B or GO_C as the “operator” of the Generator
Interconnections Facility. Rather, it is most appropriate to place the obligation to coordinate operations on both
parties. By placing the obligation on both parties, they share an equal burden to comply with the applicable
standards.Placing the obligation to coordinate operations on both GO_B and GO_C does not increase the burden
to the Transmission Operator.
If there is trouble at the point of interconnect substation, the Transmission Operator might need to coordinate operations
with GO_A, GO_B and GO_C in either Scenario 1 or Scenario 2. If in Scenario 2, the Transmission Operator only issued
26
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
instructions to GO_A and GO_B, they could not be sure that GO_C would receive the instructions. Furthermore, since
GO_B is not a Transmission Operator, they lack the authority to issue instructions to GO_C.
We recommend an additional requirement to resolve coordination between generators. For example “Generator Operators
interconnected through a common Generator Interconnection Facility shall coordinate their operations.”
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
SERC Planning
Standards
Subcommittee
No
We suggest 3 alternate modified definitions:
Right-of-Way (ROW)A corridor of land on which a Transmission Line or Generator Interconnection Facility may be located.
The owner of the Transmission Line or Generator Interconnection Facility may own the land in fee, own an easement, or
have certain franchise, prescription, or license rights to construct and maintain lines.
Vegetation InspectionThe systematic examination of a Right-of-Way to document vegetation conditions.The main reason
for the change in definition for ROW was the proposed use of the non-capitalized term "electric line". Since the use of that
phrase sometimes means distribution lines as well as transmission, we suggest staying with the capitalized NERC terms
for better clarity.
Generator OperatorThe entity that operates generating unit(s) and performs the functions of supplying energy and
Interconnected Operations Services. The Generator Operator may also operate the Generator Interconnection Facility.
The main reason for the change in the definition for Generator Operator was that the 2nd sentence in the proposed
definition was a requirement and not a true definition. The other change was to allow for the case where the Generator
Operator was not the operator of the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE,
Power Operations
Services
Yes
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
27
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Detroit Edison
Company
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
Florida Municipal
Power Agency
Yes
Ingleside
Cogeneration, LP
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra
Generation
Yes
South Carolina
Electric and Gas
Yes
Tenaska, Inc.
Yes
Question 3 Comment
28
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Pepco Holdings,
Inc - Affiliates
Yes
Question 3 Comment
“Generator Interconnection Facility” is useful to allow GOs to be distinguished from TOs and their responsibilities.
“Generator Interconnection Operational Interface” is also known as the “Point of Interconnect” by the RTO. This may be
an alternate name that could be used to make things standard.
Response: The SAR DT thanks you for your comment. Because of potential confusion with language in various interconnection agreements, the SAR DT will
not make changes to this definition and will defer to the SDT.
Southern
California Edison
co.
Yes
Additional clarification would be useful as it/ they would cut down on future requests for interpretation... i.e provide a
specific threshold for the proposed Generator interconnection Facility definition
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Energy Standards
Working Group
Yes
In particular we support the revised definition of the Generator Interconnection Facility, which has appropriately
incorporated our comments from the draft of the Team’s report
Response: The SAR DT thanks you for your comment.
29
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
4. Do you agree with the proposed new requirements intended to add clarity around expectations for generator
owners and operators at the transmission interface?
Summary Consideration: A number of responses expressed concern about the need for various proposed new requirements. An in-depth
review of the comments, however, indicated that most of the concerns could be addressed by the SDT. As a result, many of these comments will
be referred to the SDT for their consideration, including final resolution of which standards need to be modified. Revisions to the SAR also allow
the SDT the option of merging the changes into one new standard or an existing standard(s).
Organization
Kansas City Power &
Light
Yes or
No
No
Question 4 Comment
o PER-001, R1: The language proposed for PER-001, R1, infers the Generator Operator is able to take independent
actions regarding the “Generation Facility” and the Generator Interconnection Facility. There is no definition for
Generation Facility in this proposal or currently in the NERC Glossary. At any rate, do not agree with the Generator
Operator taking any independent actions other than those to monitor and maintain the safe operation of a generating
unit for the production of energy and reactive power.
o PER-002, R3 (Proposed here): This infers again the Generator Operator taking independent actions with regard to
equipment within the Generator Interconnection Facility. Although, the Generation Interconnection Facility is defined
properly, that does not mean the Generator Operator is the control authority over that equipment. It is not uncommon
for the Generator Operator to operate equipment within the Generator Interconnection Facility at the direction of the
Transmission Operator. Recommend consideration be given to modify this requirement to reflect that.
o TOP-001, R9 and R10 (Proposed here): This infers again the Generator Operator taking independent actions with
regard to equipment within the Generator Interconnection Facility. Although, the Generation Interconnection Facility is
defined properly, that does not mean the Generator Operator is the control authority over that equipment. It is not
uncommon for the Generator Operator to operate equipment within the Generator Interconnection Facility at the
direction of the Transmission Operator. Recommend consideration be given to modify these requirements to reflect the
Transmission Operator can be the authority over the equipment within the Generation Interconnection Facility but that
the Generator Operator may operate that equipment at the direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Electric Power
No
AEP believes that the only new requirement that should be addressed is in reference to FAC-003. AEP does not see
benefit in expanding the scope of EOP-003, PER-001, and PER-002.With respect to TOP-004, AEP does not feel the
added requirement is necessary as the Generator Interconnection Facility should be adequately sized to handle the
output of the generator. The added requirement in TOP-008 for notification is redundant with other obligations for the
GOP to notify other entities, such as in COM-002 and TOP-003.
30
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Transmission
Company
No
Clarify the definition of generator interconnection facility to include who this applies to as shown in the conclusions
above in #3. A Generator Interconnection Facility is considered as though part of the generating facility specifically for
purposes of applying Reliability Standards to a Generator Owner or Generator Operator.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the
need for auditable reliability standards to be added between the GO/TO. Also, it is not necessary to include the phrase
“including the Generator Interconnection Facility” in all the applicable requirements. Since the term Generator
Interconnection Facility is proposed to be included in the Glossary definitions for Generator Operator, then it would be
redundant to also add the phrase throughout the applicable standards.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Public Utility District #1
of Clark County
No
Many of the new requirements place excessive demands on generators that do not increase system reliability.
In EOP-003 Generator Operators are added to the applicability and as a result R7 is a newly applicable requirement to
Generator Operators. However, this requirement now implies that Generator Operators are required to engage in the
coordination efforts (with the BA and TOP) of automatic underfrequency load shedding. Generators do not have the
option of determining what levels of frequency to ride through and what levels of frequency to trip on. Those quantities
are defined by the RC and the BA and Generator Operators are required to have generator protection system settings
that allow this ride through. Generators should have frequency and voltage ride through requirements that are
coordinated with automatic load shedding programs by the RC, BA and/or TOP but should simply be required to
comply with these requirements and shoud not have a role in the coordination. The comments in the GOTO Final
report indicate that this addition is required to ensure that a generator frequency trip set point is appropriately included
in the currently required coordination between the BA and TOP. Clark believes that generators should not participate in
the coordination but simply be required to comply with frequency ride through requirements dictated by the RC, BA
and/or TOP.
Clark believes that FAC-002 clearly applies to Generator Owners and this standard requires that generator integration
facilities address reliability impacts in the interconnected transmission system. Additionally, the proposed change to
EOP-003 appears to have nothing to do with the issue at hand (i.e. removal of TOP status to a generator because of a
Generator Interconnection Facility).
Clark believes it is inappropriate to make EOP-003 applicable to Generator Operators and to imply that a Generator
31
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Operator has any participation in coordination of underfrequency load shedding other than to comply with frequency
ride through requirements of the RC, BA and/or TOP.
Clark agrees that the changes to FAC-003 are appropriate, will lead to increased reliability and do not result in
unnecessary reporting or paperwork. The applicability section clearly limits the scope of what Generation
Interconnection Facilities would be included in this standard by having a “two span” limit in the length of the facility.
This limit appropriately will exclude those generators that have arranged for a Transmission switchstation owned and
operated by a Transmission Operator located immediately adjacent to the generator.
In IRO-005, R13, the standard proposes to require a Generator Operator to immediately inform the TOP of status
changes to SPS. While Clark is not opposed to this change, it is unclear why the issue at hand (i.e. removal of TOP
status to a generator because of a Generator Interconnection Facility) has lead to this addition. The SAR implies that
the industry need leading to the SAR is the “registration of Generator Owners and Generator Operators as
Transmission Owners and Transmission Operators, based on the facilities that connect the generators to the
interconnected grid.” IRO-005, R13 does not appear to have any connection to this industry need.
In PER-001, Generator Operators are added to the applicability and as a result of the new R2 Generator Operators will
be required to demonstrate the authority of operating personnel over Generation Facilities and Generation
Interconnection Facilities. This level of authority is unnecessary. Transmission Operators already have this authority
(refer to PER-001, R1). Generator Operators are already required to comply with reliability directives issued by RCs,
BAs, and TOPs in other reliability standards. The requirement to demonstrate that a generator needs this authority
over its generating facility is unnecessary and has no connection with the industry need the SAR is based on. A
generator operator has authority over its generator by virtue of its registration as a Generator Operator. The need for
further proof that a GOP can operate generation facilities for which it is a registered GOP has not been demonstrated.
The requirement to demonstrate that a generator needs authority over a Generation Interconnection Facility is; for the
same reason, unnecessary. A generator operator has authority over its generator by virtue of its registration as a
Generator Operator for that facility. The need for further proof that a GOP can operate Generation Interconnection
Facilities for which it is a registered GOP has not been demonstrated.
In PER-002, Generator Operators are added to the applicability and as a result of the new R3 Generator Operators will
be required to demonstrate training programs similar to TOP training requirements. Clark is not opposed to training its
GOP personnel; however, including the training program within the PER-002 training requirements elevates this
training to a level that has not been demonstrated to be necessary in all cases. Currently, this requirement is
applicable to a TOP. By removing the TOP classification to certain GO/GOP registered entities that are only a TOP by
virtue of Generation Interconnection Facilities, the potential exists that inadequately trained personnel may be directing
the operation of a Generation Interconnection Facility. However, as stated earlier, when the Generation
Interconnection Facility is short in length and more importantly when this facility has no devices which can be operated
(i.e. direct connection between the generator step-up transformer or generator protection circuit breaker (owned or
32
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
operated by the GOP) and the TOP owned and operated transmission breaker) there is no gap in having adequately
trained personnel operating transmission facilities. Clark believes the applicability section should include minimal limits
for applicable Generation Interconnection Facilities or that the definition of Generation Interconnection Facilities should
be amended such that PER-002 applicability is limited to GOPs that own facilities that are similar in nature to the New
Harquahala Generation Interconnection Facilities that have led to this SAR.
The proposed changes to TOP-004 are confusing. The proposal does not add GOP in the applicability section but the
newly proposed R7 appears to obligate GOPs. The requirement should be revised to obligate a TOP to ensure that a
GOP operates within its applicable limits. These limits should have already been established.
In FAC-008 Transmission Owners and Generator Owners are required to have a ratings methodology.
In FAC-009 TOs and GOs are required to calculate facility ratings. In both of these standards, documentation is to be
made available to RCs, TOPs, PAs and TPs that have responsibility. At the very least, the applicability section of a
standard should be coordinated with the entities having obligations due to the requirements of a standard.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.)
Luminant
No
No, for the bulk of the Generator Owners whose Generation Interconnection Facilities (GIF) are connected in close
proximity (i.e., one-half mile or less) to the BES, the requirements will only add additional unduly burdensome
documentation, paperwork and compliance risk, with no reliability benefit
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Independent Electricity
System Operator
No
Please see our comments under Q5 where we comment on both the additions and modifications to the standards.
ISO RTO Council
Standards Review
Committee
No
Please see our comments under Q5 where we comment on both the additions and modifications to the standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI considers the phrase “for SPS relay or control equipment under its control” to be confusing and ambiguous in the
new requirement IRO-005 R13. We suggest deletion of this phrase maintains the intent of the requirement and
removes the unclear reference to the subject associated with the word “its”.
33
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
PPI questions why the sub-elements of new requirement TOP-001 R9 are stipulated in bullet item format rather than
sub-requirement format.
PPI agrees with the first portion of new requirement PER-001 R2. Regarding the second portion of new PER-001 R2,
the Generator Operator is already required to comply with Reliability Coordinator directives as established in IRO-001
R8 and TOP-001 R3, and further the Generator Operator is already required to comply with Transmission Operator
directives also as established in TOP-001 R3. PPI does not see any benefit in reiterating the Generator Operator
responsibility and authority to follow directives in this new requirement. PPI would suggest stipulating the Generator
Operator be responsible for following directives of the Balancing Authority in a separate Requirement or subrequirement, and not lumped into this new requirement.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT. The bulleted items in TOP001 R9 should have been numbered. We’ll pass this comment on to the SDT.
Duke Energy
No
See detailed comments under Question 5 below.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE, Power
Operations Services
No
See response to Item #2.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard or
an existing standard(s).
Midwest ISO Standards
Collaborators
No
The requirement additions to the TOP standards parallel requirements that the Real-Time Operations standards
drafting team has already proposed for removal. This project needs to be coordinated with the Real-Time Operations
project.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Tenaska, Inc.
No
TOP-001 R10 should be amended such that the proposed R10 reads as follows: The Transmission Operator shall have
decision-making authority over operation of the Generator Interconnection Operational Interface at all times in order to
preserve interconnection reliability, unless by exercising that authority such actions would violate safety, equipment,
regulatory or statutory requirements. Under these circumstances the Generator Operator shall immediately inform the
Reliability Coordinator or Transmission Operator of the inability to perform the directive so that the Reliability
34
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Coordinator or Transmission Operator can implement alternate remedial actions.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina Electric
Membership Corporation
No
We agree with most of the new requirements with the exception of two:
1) New requirement R9 of TOP-001 appears to be very similar to existing requirements of TOP-001 (req R7) and TOP003 (req R1). Further clarification is needed to distinguish the differences between this new requirment and existing
requirements.
2) New requirement R5 of TOP-008 directs the GOP to disconnect the GIF when “safety is jeopardized” or... which
triggers the immediate question: Who’s safety does the Ad Hoc group refer to, the personnel of the GO/GOP or the
safety of the transmission system or its personnel or both possibly? Please clarify. If it the safety of the transmission, its
personnel or the system grid in general, then why would it not be the TOP's responsibility to provide a directive of this
nature since the TOP would have a greater perspective/visibility than the GO/GOP of the system operating conditions
in real time?
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Energy Standards
Working Group
No
We are supportive of most of the new requirements being suggested with the following two exceptions:
IRO-005 R13 which states:R13. The Generator Operator shall immediately inform the Transmission Operator of the
status ofthe Special Protection System, including any degradation or potential failure to operate as expected for SPS
relay or control equipment under its control.We believe that this proposed additional requirement is redundant as it is
already covered by the requirements of PRC-001-1
ANDTOP-001 R10 which states:The Transmission Operator shall have decision-making authority over operation of
theGenerator Interconnection Operational Interface at all times in order to preserveInterconnection reliability.
We would amend the proposed R10 as follows: The Transmission Operator shall have decision-making authority over
operation of the Generator Interconnection Operational Interface at all times in order to preserve interconnection
reliability, unless by exercising that authority such actions would violate safety, equipment, regulatory or statutory
requirements. Under these circumstances the Generator Operator shall immediately inform the Reliability Coordinator
or Transmission Operator of the inability to perform the directive so that the Reliability Coordinator or Transmission
Operator can implement alternate remedial actions.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
35
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Electric Market Policy
Yes or
No
No
Question 4 Comment
We feel it is not necessary to include the phrase “including the GeneratorInterconnection Facility” in all the applicable
requirements. The term Generator Interconnection Facility is proposed to be included in the Glossary definitions and
the proposed definition of Generator Operator includes the following language “also operates the Generator
Interconnection Facility and is responsible for coordinating with the Transmission Operator when the facility is
energized or about to be energized to/de-energized from the transmission system” which we feel is sufficient and
superior to having the phrase repeated throughout the applicable standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
No
We feel it is not necessary to include the phrase “including the GeneratorInterconnection Facility” in all the applicable
requirements. The term Generator Interconnection Facility is proposed to be included in the Glossary definitions and
the proposed definition of Generator Operator includes the following language “also operates the Generator
Interconnection Facility and is responsible for coordinating with the Transmission Operator when the facility is
energized or about to be energized to/de-energized from the transmission system” which we feel is sufficient and
superior to having the phrase repeated throughout the applicable standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
California ISO
Yes
Competitive Power
Ventures, Inc.
Yes
El Dorado Energy LLC
Yes
Entegra Power Group
LLC, i.e., Gila River
Power and Union Power
Partners
Yes
Florida Municipal Power
Agency
Yes
Ingleside Cogeneration,
Yes
36
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
LP
Manitoba Hydro
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra Generation
Yes
SERC Planning
Standards Subcommittee
Yes
South Carolina Electric
and Gas
Yes
Southern California
Edison co.
Yes
Additional clarification would be useful as it/ they would cut down on future requests for interpretation.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc Affiliates
Yes
Application of FAC-003 for Gen Interconnect Facilities that are "two spans, generally 1/2 mile or more past the property
line" is reasonable as long as the "property line" remains in the definition. OK.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation Power
Source Generation Inc.
Yes
Constellation agrees with the proposed new requirements in principal. However, further clarity is needed in the
requirements so that there isn’t any added confusion. Either an implementation plan or a “frequently asked questions”
document would be recommended.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Bonneville Power
Administration
Yes
However, believe there is a problem with #8 referring to TOP-008. The solution to the generator facilitiy line overload
may be a transmission system problem so the Generatior should not disconnect unless the TOP directs it to do
37
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
so(confer unless a safety issue). Also, TOP-001 needs careful work. The transmision system doesn't want
environmental issues turning off generators during emergency or critical transmission conditions.
Entegra Power Group
LLC
Yes
SEE COMMENTS FOR QUESTION 2.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
38
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
5. Do you agree with the proposed modified requirements intended to add clarity around expectations for
generator owners and operators at the transmission interface?
Summary Consideration: A number of responses expressed concern about the proposed modifications. An in-depth review of the
comments indicated that most of the concerns could be addressed by the SDT during the standards drafting process. Based on discussions
with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings, the SAR DT modified the SAR to give the
SDT the flexibility to consider further modifications not identified in the Ad Hoc Report.
Organization
Independent
Electricity System
Operator
Yes or
No
Question 5 Comment
(1) We realize that the SDT needs to make changes to “approved standards” but there are a number of standards involved
in this project whose newer versions have either received the BoT approval, or about to be adopted by the BoT or at the
stage of being finalized or balloted. To make changes to the soon to be outdated versions is confusion and will require a
subsequent change when FERC approves the standards. We therefore suggest the SDT to also mark up those which have
newer versions already or soon to be adopted by the BoT and those that are being balloted. Alternatively, the SDT may
want to post the changes to those FERC approved standards only, and defer actions on those that have not been approved
by FERC and those that are being revised/balloted until FERC approves them.
(2) EOP-001: R7.3 has been changed to add the term “..., including outages to the Generator Interconnection Facility, to
maximize .....”. It is not clear whom the TOP and the BA should coordinate with and it does not place a requirement on the
entity that is responsible for the Generator Interconnection Facility outage planning and scheduling. We suggest to add the
appropriate responsible entity (Generator Owner?) to the Applicability Section, and add this entity to R7.3.
(3) In EOP-008 R1.3, is it the intent of the revised requirement that the plan address monitoring and control of ALL
Generator Interconnection Operational Interface[s] or just the critical ones (as with the critical transmission facilities)?
(4) R10 of TOP-001 is not written in the form of a requirement. We suggest replacing “have” with “exercise”. Thus, the
requirement would read “The Transmission Operator shall exercise decision-making authority over operation of the
Generator Interconnection Operational Interface...”
(5) TOP-004: The Applicability Section needs to be revised to add Generator Operator to reflect the new requirement R7.
We also suggest the SDT to evaluate if there is an alternative or more suitable place for this requirement than the TOP
standard.
(6) A number of standards are missing their VSLs. Most VSLs have similar wording in the requirements so many of them
will need to be revised to reflect changes to the requirements proposed in this project.
39
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT. The redlines were only
intended to provide stakeholders with an idea of the proposed scope of changes – the team recognizes that any new/revised requirement may result in
associated changes to the VRFs, Time Horizons, VSLs, data retention, measures, etc.
Energy Standards
Working Group
No
Comments: see my note re FAC-003
We are supportive of the modified requirements being suggested with the following exception:
FAC-003:We offer the following suggested changes for greater clarity.
4. Applicability:Replace the proposed sections 4.4 and 4.5 with the following:4.4. Generator Owner that owns a Generator
Interconnection Facility above 200 kV that exceed two spans from the generator property line or are below 200 kV and
deemed critical to the reliability of the electric system by the Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and subsequent sections of the
standards, it is clear that the use of the words “Generator Owner” refers only to the subset of Generator Owners as
specified by section 4.4, not to all Generator Owners included in the NERC Registry.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation
Power Source
Generation Inc.
No
Constellation agrees with the proposed changes for BAL-5, EOP-1, EOP-4, EOP-8, FAC-1, FAC-8, FAC-9, IRO-5, MOD-10,
MOD-12, PER-1, PRC-1, PRC-5, TOP-1, TOP-2, TOP-3, VAR-1, and VAR-2. Furthermore, the changes made to CIP-2 are
especially valuable in that the clarity it brings with the added terminology would assist in identifying individual assets.
Constellation does not agree with (or has comments for) the proposed changes to:
oEOP-3 - GOs/GOPs should not be included in this standard
oFAC-3 - Constellation agrees in principal with this change, but further work is needed in regards to which GOs fall into this
category. The wording may be changed to “two or more spans exceeding ½ mile in total length,” but further discussions is
needed on this topic.
oPER-2 - Constellation agrees in principal with this change, but believes that this requirement should be combined into
PRC-001 R1, and eliminate the redundancy.
oPRC-5 - Testing of the Protection System of the Generator Interconnection Facility is not always the sole responsibility of
the GO. Some verbiage attesting to that is needed. Otherwise, it is wise to include the Generator Interconnection Facility
into this standard so that no gap may exist in the testing of a Protection System that may impact the BES.
40
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need
for auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Duke Energy
No
o General Comment - The Standards Drafting Team (SDT) will need to make sure that Measures are developed or
modified to correspond to new or revised requirements of the standards.
o Process Question - Will the SDT fold these standards revisions into other projects, or will new versions be created as part
of this project?
o FAC-003-1 - Applicability sections 4.4 and 4.5 should be combined to make it clear that the standard only applies to the
Generator Owner’s GIF. Does the 2-span limit mean that there are three towers? What criteria will the Regional Entity use
to deem a GIF critical? The language about the generator property line is confusing - how does it compare to the Right-ofWay (ROW) definition? In some cases the TO may own the ROW, while the GO owns the GIF.
o FAC-008-1 - Requirement R1 raises a question regarding whether a GIF can be jointly owned by a TO and a GO. If a TO
is an owner, then the GIF is not a GIF but a transmission facility, right?
o FAC-009-1 - We don’t think revisions are needed to R1 and R2, since the term “Facilities” already implicitly includes GIF.
If you don’t agree, then perhaps a more straightforward approach would be to revise the definition of “Facility” to explicitly
include the GIF.
o IRO-005-2 - We think that you don’t need to specifically add the GIF to R9 because it would have to already be included
in the requirement as part of any generation outage coordination. Under R13 we would change “the Special Protection
System” to “any Special Protection System”. We also note that this new R13 propagates the poor language of R12 (i.e.,
how does anyone define “a potential failure to operate”?).
o PER-001-0 - Applicability section 4.3 should be expanded to make it clear that Requirement R2 only applies to the
Generator Operator with respect to the GIF, and R2 should be likewise revised. The GOP is already obligated under TOP001-1 Requirement R3 to comply with RC and TOP directives unless such actions would violate safety, equipment,
regulatory or statutory requirements. Suggested rewording of Applicability section 4.3 : “Generator Operators -This
standard shall apply to Generator Operators who own a Generator Interconnection Facility.” Suggested rewording of
Requirement R2 : “For Generation Facility Interconnection equipment under their direct control, each Generator Operator
shall provide operating personnel with the responsibility and authority to implement real-time actions and to follow reliability
41
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
directives of Reliability Authorities, Transmission Operators and Balancing Authorities, to ensure the stable and reliable
operation of the Generation Interconnection Facility.”
o PER-002-0 - Applicability section 4.3 should be expanded to make it clear that Requirement R2 only applies to the
Generator Operator with respect to the GIF. Suggested rewording of Applicability section 4.3 : “Generator Operators -This
standard shall apply to Generator Operators who own a Generator Interconnection Facility.”
o PRC-001-1 - Changes to PRC-001-1 should probably not be made right now, because it is already a vague standard, and
was the subject of an Interpretation (Project 2009-30) which was voted down in February.
o TOP-003-0 - Requirement R1 and its sub-requirements are poorly written. We suggest folding R1.3 into R1 with this
suggested rewording: “Generator Operators and Transmission Operators shall provide planned outage information by 1200
Central Standard Time for the Eastern Interconnection and 1200 Pacific Standard Time for the Western Interconnection, as
follows : “
o TOP-004-2 - We question whether Requirement R7 is appropriate, since by definition the GIF is not part of the
transmission system network and does not fit with the Purpose statement of this standard. If R7 is retained, then you need
to add Generator Operator to the Applicability section.
o TOP-008-1 - Need to add GOPs to the Purpose statement.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
California ISO
No
Please see our comments under Question 2 above. In addition, with regard to the proposed change to Standard PRC-001,
the California ISO (CAISO) questions the need for a BA to understand the purpose and limitations of protection schemes
associated with all of the Generator Interconnection Facilities in its area given a BA’s role is to balance
load/generation/interchange which does not require the BA to operate any generator or BES facilities, or to understand the
characteristics or limitations of any equipment. Any potential loss of one or more generator due to protection or equipment
issues will need to be communicated by the GO or GOP to the BA for consideration in reserve calculation
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI does not agree with the modification to EOP-003 R7. The Generator Operator does not have load to be shed,
therefore none to be coordinated. If the drafting team is intending to require the Generator Operator to coordinate the
underfrequency relay settings on their resources with load shedding plans established by the Transmission Operator and
Balancing Authority, this is an appropriate requirement. The modification, though, does not accomplish this.PPI questions
why the sustained line outages reported quarterly to the RRO pursuant to FAC-003 R3 by the Generator Owner, as
modified, are not reported to NERC in Requirement 4 of the same Standard.
42
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE, Power
Operations
Services
No
See response to Item #2.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard
or an existing standard(s).
Luminant
No
The following comments are specific to each standard
CIP-002 - This standard is currently under revision and any change should be addressed by the Cyber Security Standards
Revision Team.
EOP-003 - Application of this reliability standard to a GOP is incorrect. The Generator Operator has no direct responsibility
for load shedding. Only the TOP and BA have load shedding responsibility.
EOP-004 - The inclusion of GIF in this reliability standard is redundant as the GOP has responsibility for all of its facilities,
including any generators. . Since generation units are not independently identified with a particular GOP, the GIF does not
need to be independently identified. Also, there is a NERC project currently underway to revise this standard (Project 200901).
FAC-003 - Luminant agrees this standard should apply in those instances when the generator is connected to the BES
through its GIF over a substantial distance. However, the applicability of this standard to a GIF needs to specify a distance
(such as one-half (½) mile from the plant property boundary) not a number of spans since the spacing between spans can
vary from extensively. Defining the applicability of this standard in terms of a number of spans will create inconsistency in
the application of the requirements.
IRO-005 - New requirement R13 presumes that a Special Protection System (SPS) is the sole responsibility of a GOP,
which, in most cases, it is not. Most SPS are the responsibility of the TO, not the GOP. This requirement does not define
which SPS is being monitored. A requirement of this nature should define an SPS on the GIF.
PER-001 - The addition of a requirement applicable to GOP in this standard goes well beyond the scope of this project’s
purpose. A NERC Standards Drafting Team, under Project 2006-01, did not add any GOP requirements to the PER
standards. This proposed GOP requirement is redundant. Current NERC Reliability Standard TOP-001, R3 requires
Generator Operators to follow reliability directives, as does IRO-001, R8. This proposed requirement should be deleted. It
adds paperwork, documentation and compliance risk with no reliability benefit. The PER-001 standards were intended for
overall grid management, not the operation of a power plant.
43
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
PER-002 - The recent NERC Standards Drafting Team, under Project 2006-01, specifically declined to make this standard
applicable to GOP. In addition, the 2006-01 project is retiring this standard with the adoption of the revised PER-005.PRC001 - The inclusion of Generator Interconnection Facility is redundant. However, there is a current NERC Drafting team
revising PRC-001 and this issue should be referred to that team.
PRC-005 - Any revisions to PRC-005 should be referred to the current PRC-005 drafting team.
TOP-001 - Draft Requirements R9 and R10 are extremely broad. These should only apply to narrowly defined GIFs such
as long span connections or GIFs with transmission load flowing through the GIF. Care should be taken in this requirement
not to duplicate requirements such as coordination of outage planning. The requirements should be specific, and not fill in
the blank for the TOP or region.
TOP-004 - Draft Requirement R7 is redundant to requirements in other standards and is not needed.
IR0-005-2, R13, and IRO-005-3, R10, require the GOP to operate the BES to its most limiting factor, which is, by definition,
implicitly within its facility ratings.
TOP-008 - Does draft requirement R5 fit in this standard that addresses IROL and SOL? This requirement should only
apply to the same long connection GIF facilities identified in TOP-003.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Florida Municipal
Power Agency
No
The modification of EOP-003-1, R7 is inconsistent with the requirement. The original requirement requires the BA and TOP
to coordinate with others (presumably DPs, TOs and GOPs) in their area for various automatic action (e.g., UFLS,
automatic tripping of cap banks, and frequency capabilities of generators for instance). The GOP has no “area” to
coordinate and no one within its area to coordinate with. So, it is the BA and TOP that coordinate within their area, not the
entities embedded within the BA or TOP area. Otherwise, we ought to add at a minimum DPs, LSEs, and TOs to the list.
The modifications to EOP-004-1 R2; FAC-001-0 R1.1; FAC-008-1; FAC-009-1; MOD-010, MOD-012, PRC-001, PRC-004;
PRC-005; TOP-001-1 R7; TOP-002 R3 and R18; TOP-003 R1 and R1.1; and VAR-002 R3.2 are redundant with no need to
specifically call out the Generator Interconnection Facility. The interconnection facilities are facilities and already included in
the term “on its system or facilities” and “generating facilities”, etc. And, the Generator Owner and Operator are already
responsible for their interconnection facilities in the definition of those Entities. Specifically calling out the interconnection
facilities calls into question why other facilities are not specifically called out.
As discussed in the response to #2 above, addition of the Generator Owner to FAC-003 over-steps Federal Power Act
Section 215 since radial transmission lines to generating plants will not participate in a cascading outage since the loading
of radial facilities to power plants will not change significantly with outages on the interconnected system.
44
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina
Electric
Membership
Corporation
No
We agree with most all of the modified requirements with one exception:
For FAC-003, regarding the "two-span criteria" or "about 0.5 miles" test for generator applicability, we would like the ad hoc
team to consider providing more direction or greater specificity that makes a GIF of two or less spans to become exempt,
while one of greater than two spans (0.5 mile) but less then 5 spans (0.8 miles) to suddenly become subject to the FAC-003
standard requirements. The "generator's line-of sight" rule as described in response to item #3 in the Final Report in our
opinion should be clearly specified in the FAC-003 proposed standard change at a minimum to avoid mis-interpretations.
Also, regarding item #10 issue in the report, we would like the ad hoc team to consider proposing a 4th proposal which
would be a hybrid between Proposal 2 and Proposal 3 as reported within the Final Report which would provide a “bright-line
test” as to what generators are exempt or not to the FAC-003 standard, rather than solely relying on Proposal 2 which relys
on the physical attributes of the GIF in ruling out generators subject to FAC-003. If the GIF is 3-4 spans or 0.53 miles in
length, but still within the "line of sight" of the GOP, then allow the GOP working with the RE and TOP to rule out smaller
generators that are immaterial to the reliability of the grid.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Tenaska, Inc.
No
We are supportive of the modified requirements being suggested with the following exception related to the suggested
changes on FAC-003 for which we offer the following modification for greater clarity:
4. Applicability:Replace the proposed sections 4.4 and 4.5 with the following:
4.4. Generator Owner that owns a Generator Interconnection Facility above 200 kV that exceed two spans from the
generator property line or are below 200 kV and deemed critical to the reliability of the electric system by the
Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and subsequent sections of the
standards, it is clear that the use of the words “Generator Owner” refers only to the subset of Generator Owners as
specified by section 4.4, not to all Generator Owners included in the NERC Registry.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Midwest ISO
Standards
Collaborators
No
We do not agree with the modification to EOP-003 R7. The Generator Operator does not have load shed to coordinate.
We believe the drafting team is intending to require the Generator Operator to coordinate underfrequency relay settings on
their generators with the BA and TOP load shedding plans. We agree this is appropriate but the modification does not
45
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
accomplish this.
EOP-004 R2 seems to be modified unnecessarily. System and facilities are already included in the requirement and, thus,
would include the Generator Interconnection Facility.
We do not agree adding Generator Interconnection Operational Interface to R1.3 in EOP-008. The sub-requirement
already requires the contingency plan to consider generation control which would require consideration of the Generator
Interconnection Operational Interface. Furthermore, there is a lack of coordination with the project to update this standard.
A newer, significantly modified version of this standard has already been through an initial ballot period.
IRO-005 R9 modifications are not needed. The requirement already requires an RC to coordinate pending generation
outages. This would have to include any outage such as the Generator Interconnection Facility.Many of the changes to the
TOP standard are modifying requirements that the Real-Time Operations standards drafting team has already proposed for
removal. This project needs to be coordinated with the Real-Time Operations project.
VAR-001 R8 modifications are not necessary because the TOP is already required to operate reactive generation
scheduling. They can’t do this without considering the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
ISO RTO Council
Standards Review
Committee
No
While we generally agree with the proposed wording change, we have a number of comments the first of which is a timing
decision issue.
(1) We realize that the SDT needs to make changes to “approved standards” but there are a number of standards involved
in this project whose newer versions have either received the BoT approval, or about to be adopted by the BoT or at the
stage of being finalized or balloted. To make changes to the soon to be outdated versions is confusing and will require a
subsequent change when FERC approves the standards. We therefore suggest the SDT to coordinate their changes with
the other drafting teams that are working on the newer versions already or soon to be adopted by the BoT and those that
are being balloted. Alternatively, the SDT may want to post the changes to those FERC approved standards only, and defer
actions on those that have not been approved by FERC and those that are being revised/balloted until FERC approves
them.
(2) EOP-001: R7.3 has been changed to add the term “..., including outages to the Generator Interconnection Facility, to
maximize .....”. It is not clear with whom the TOP and the BA should coordinate with and it does not place a requirement on
the entity that is responsible for the Generator Interconnection Facility outage planning and scheduling. We suggest
removing the changes on this requirement all together. Generator maintenance will include the Generator Interconnection
Facility. These are extra words that are not needed.
(3) A number of standards are missing their VSLs. Most VSLs have similar wording in the requirements so many of them
46
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
will need to be revised to reflect changes to the requirements proposed in this project.
(4) We do not agree with the modification to EOP-003 R7. The Generator Operator does not have load shed to coordinate.
We believe the drafting team is intending to require the Generator Operator to coordinate underfrequency relay settings on
their generators with the BA and TOP load shedding plans. We agree this is appropriate but the modification does not
accomplish this.
(5) EOP-004 R2 seems to be modified unnecessarily. System and facilities are already included in the requirement and,
thus, would include the Generator Interconnection Facility.
(6) We do not agree adding Generator Interconnection Operational Interface to R1.3 in EOP-008. The sub-requirement
already requires the contingency plan to consider generation control which would require consideration of the Generator
Interconnection Operational Interface. Furthermore, there is a lack of coordination with the project to update this standard.
A newer, significantly modified version of this standard has already been through an initial ballot period.
(7) IRO-005 R9 modifications are not needed. The requirement already requires an RC to coordinate pending generation
outages. This would have to include any outage such as the Generator Interconnection Facility.
(8) PRC-001: We question the need for a BA to understand the purpose and limitations of protection schemes associated
with all of the Generator Interconnection Facilities in its area given a BA’s role is to balance load/generation/interchange
which does not require the BA to operate any generator or BES facilities, or to understand the characteristics or limitations
of any equipment. Any potential loss of one or more generator due to protection or equipment issues will need to be
communicated by the GO or GOP to the BA for consideration in reserve calculation.
(9) Many of the changes to the TOP standard are modifying or adding parallel requirements that the Real-Time Operations
standards drafting team has already proposed for removal. This project needs to be coordinated with the Real-Time
Operations project to assess the need for these additions/modifications.
(10) VAR-001 R8 modifications are not necessary because the TOP is already required to operate reactive generation
scheduling. They can’t do this without considering the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Bonneville Power
Administration
Yes
Competitive Power
Ventures, Inc.
Yes
47
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Detroit Edison
Company
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
First Wind
Yes
Ingleside
Cogeneration, LP
Yes
Kansas City Power
& Light
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
Question 5 Comment
48
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
South Carolina
Electric and Gas
Yes
Southern California
Edison co.
Yes
Question 5 Comment
Additional clarification would be useful as it/ they would cut down on future requests for interpretation
Response: The SAR DT thanks you for your comment.
American Electric
Power
Yes
AEP feels that a majority of the standards that were modified add clarity. We reserve the right to comment when the
Standard Drafting Team posts the draft Standard(s).
Response: The SAR DT thanks you for your comment. There will be additional opportunities to comment on the specific proposed modifications when the
project progresses to standard drafting.
Public Utility
District #1 of Clark
County
Yes
Except as discussed in comments 2, 3, and 4, Clark is in agreement with the proposed changes.
Response: The SAR DT thanks you for your comment.
American
Transmission
Company
Yes
For FAC-009 [Establish and Communicate Facility Ratings], we believe that the additional wording to highlight that the term
“Facilities” includes “Generation Interconnection Facilities” is superfluous, and therefore, it should not be added. The
proposed new and revised definitions provide more than enough clarity
For MOD-010 [Steady State Data for System Modeling], we believe that the additional wording of “for plant and Generator
Interconnection Facilities” is superfluous, and therefore, it should not be added. The proposed new and revised definitions
provide more than enough clarity.
For MOD-012 [Dynamic System Data for System Modeling], we believe that the additional wording of “for plant and
Generator Interconnection Facilities” is superfluous, and therefore, it should not be added. The proposed new and revised
definitions provide more than enough clarity.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Entegra Power
Yes
SEE COMMENTS FOR QUESTION 2.
49
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Group LLC
Response: The SAR DT thanks you for your comment. Please see the response to your comments on Question 2.
Manitoba Hydro
Yes
The modifications at this point appear appropriate.
Response: The SAR DT thanks you for your comment.
Pepco Holdings,
Inc - Affiliates
Yes
There should be a clause that the TO shall be responsible for FAC-003 activities inside the TO's substation regardless of
ownership of the Generation Interconnection Facility so we don't have to coordinate entry, etc. and they will likely have this
handled for the bulk of their property anyway.R3 quarterly reporting of outage caused by vegetation is excessive for GOs.
GOs would probably survey and cut as needed their Right of Ways at least once a year and probably already do so. TOs
probably perform vegetation management on a multi-year cycle, so they might need to note quarterly if there is a veg.
incident that occurs one or two quarters before the next round of survey/management on that line.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. There were many suggestions for additional or alternate modifications to
FAC-003 and these suggestions will be addressed by the SDT.
50
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
6. Do you believe there are any other Transmission Owner or Transmission Operator standards or requirements
that should be applicable to the Generator Owner or Generator Operator other than those identified?
Summary Consideration: Stakeholders did not indicate the need to include any requirements or standards that were not already contained
in the SAR. However, based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings,
the SAR DT modified the SAR to give the SDT the flexibility to consider further modifications not identified in the Ad Hoc Report.
Organization
Yes or No
AmerenUE, Power Operations
Services
No
American Transmission
Company
No
Bonneville Power Administration
No
California ISO
No
Competitive Power Ventures, Inc.
No
Constellation Power Source
Generation Inc.
No
Detroit Edison Company
No
E.ON U.S.
No
El Dorado Energy LLC
No
Electric Market Policy
No
Energy Standards Working
Group
No
Question 6 Comment
51
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Entegra Power Group LLC
No
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
No
First Wind
No
Florida Municipal Power Agency
No
Independent Electricity System
Operator
No
Ingleside Cogeneration, LP
No
ISO RTO Council Standards
Review Committee
No
Luminant
No
Mesquite Power
No
Midwest ISO Standards
Collaborators
No
North Carolina Electric
Membership Corporation
No
Pepco Holdings, Inc - Affiliates
No
Prairie Power, Inc.
No
PSEG Companies
No
Question 6 Comment
52
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Public Utility District #1 of Clark
County
No
Sempra Generation
No
SERC Planning Standards
Subcommittee
No
South Carolina Electric and Gas
No
Tenaska, Inc.
No
American Electric Power
No
Question 6 Comment
At this point in time, AEP cannot identify any other TO/TOP requirements that should be considered.
Response: The SAR DT thanks you for your comment.
Southern California Edison co.
No
Do not feel that this question is in the scope of Project 2010-07 as written
Response: The SAR DT thanks you for your comment.
Duke Energy
No
However the SDT should perform a complete review.
Response: The SAR DT thanks you for your comment. The SDT will review all applicable standards changes as needed and required by the scope and
purpose of the SAR.
Manitoba Hydro
No
No manpower available at this time to examine all possibilities and scenarios.
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
No
Not at this time.
Response: The SAR DT thanks you for your comment.
53
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
7. The next posting of the proposed revisions to these standards will include conforming changes to the measures
and compliance elements, and will include an implementation plan. Please identify how much time you feel an
entity will need to become fully compliant with the following new/revised requirements:
The Generator Operator who has responsibility for monitoring the status of a special protection system or remedial action scheme at the
generating facility for the benefit of Bulk Electric System reliability should notify the Transmission Operator when a change in status or
capability occurs. (IRO-005)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question and its subcomponents. This series of
questions was meant to provide input for the SDT in development of the required implementation plan that will accompany this project as it
moves forward. The SAR DT would like to note that the three challenges most cited were training, agreements, and technical details. This
information will be referred to the SDT for their consideration.
Organization
Pepco Holdings, Inc - Affiliates
Time
Question 7 Comment
No SPS currently in system.
Response: The SAR DT thanks you for your comment.
California ISO
We are not a GOP and hence we are unable to comment on this and other questions addressing the GOP
compliance. However, the CAISO has the following comments on the effort required for other aspects of
this Project:
o As discussed under the answer to Question 5 above, it is not clear if the proposed changes to PRC-001
will require the Balancing Authority (BA) to understand the purpose and limitations of protection schemes
associated with all of the Generator Interconnection Facilities in its area, even if such facilities are not
under the control of the BA. If this is the case, significant and time-consuming effort will be required to
identify the technical details of all of the Generator Interconnection Facilities in the BA and develop a
training program to train applicable personnel on them. This is estimated to require up to 24 months.
o If the proposed changes are approved they will affect 16 Standards affecting CAISO registrations. Most,
if not all, of these changes will require modifications to the Reliability Standards Agreements (RSAs)
between the CAISO and its Participating Transmission Operators to reflect the new wording and any
delegated tasks. This may require 12 to 24 months to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
54
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
Kansas City Power & Light
12 months
Question 7 Comment
Basically this is a training issue. It takes time to prepare the training materials and to train all Generator
Operators considering shift schedules and to implement the training as part of an ongoing process.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
18 months
Luminant
18 months
55
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
South Carolina Electric and Gas
18 months
Electric Market Policy
18 months to
two years
Question 7 Comment
We feel that, in most cases, such monitoring will only require RTU connectivity of the data points as well as
incorporation into GOP control room displays.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but would probably be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Immediately
unless status
requires
change to
additional
requirements
which might
be 18 months
to two years)
The Generator Interconnection Facilities are already considered to be part of our Generator Plant and
therefore have already been included in our existing compliance program.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time
Clark has no SPS or RAS for which it is responsible.
Response: The SAR DT thanks you for your comment.
56
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Florida Municipal Power Agency
Time
Question 7 Comment
The amount of
time it takes to
compile
documentation
to fulfill the
data retention
requirements
of the
requirement
For most of these new requirements, the Entities are most likely fulfilling the requirements, but, may be
missing the documentation to prove that they are doing so. So, to be auditably (“fully”) compliant, the
Entities will need the amount of time it takes to build up sufficient evidence of compliance. This may only be
a month to develop documentation, to a longer period of time to prove periodicity (e.g., a PRC-005 type of
requirement - not PRC-005 itself - but a requirement that may need to be done periodically such as training
to show that it is done periodically.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
57
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
a. Each Generator Operator shall provide its operating personnel with the responsibility and authority to
implement real-time actions to ensure the stable and reliable operation of the Generation Facility and the
Generation Interconnection Facility, and to implement directives of the Transmission Operator and Balancing
Authority. (PER-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question and its subcomponents. This series of
questions was meant to provide input for the SDT in development of the required implementation plan that will accompany this project as it
moves forward. The SAR DT would like to note that the three challenges most cited were training, agreements, and technical details. This
information will be referred to the SDT for their consideration.
Organization
Time
American Electric Power
Question 7a Comment
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
Response: The SAR DT thanks you for your comment. These comments will be referred to the SDT.
Pepco Holdings, Inc - Affiliates
These responsibilities and authorities are already in place for other standards.
Response: The SAR DT thanks you for your comment. These comments will be referred to the SDT.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
58
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7a Comment
Regulatory
Approval
Luminant
18 months
Energy Standards Working
Group
2 years
Tenaska, Inc.
2 years
Constellation Power Source
Generation Inc.
2 years
Time is needed for training and terminology to percolate throughout the Generation Facility and that it be
ingrained with the Operators.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
6 months
Duke Energy
Approximately
24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Less than 1
year
Memo from management should suffice.
Electric Market Policy
Less than one
year
Memo from management should suffice.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Kansas City Power & Light
N/A
The Generator Operator should be operating equipment within the Generator Interconnection Facility at the
59
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7a Comment
direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No Time.
Clark’s Generator Operator personnel have responsibility and authority to implement real-time actions to
ensure the stable and reliable operation of the Generation Facility and the Generation Interconnection
Facility, and to implement directives of the Transmission Operator and Balancing Authority.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
60
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
b. Each Generator Operator shall implement an initial and continuing training program for all personnel
responsible for operating the Generator Interconnection Facility to ensure the ability to operate the equipment
in a reliable manner. (Per-002)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7b Comment
A training program for this would need to be created, procedures approved, implemented, and instituted at
all power plants for all shifts. E.ON U.S. recommends that the addition of PER-002 R3 be coordinated with
the existing standard PRC-001 R1, to eliminate redundancy.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
American Electric Power
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Pepco Holdings, Inc - Affiliates
0-2 years
Currently establish training based on the RTO requirements. It would be Conectiv’s policy to continue this
training for this requirement. If other training is imposed upon the Entities, it may require up to two years to
develop and initiate full training.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Entegra Power Group LLC
1 YEAR
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
12 months
61
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7b Comment
Membership Corporation
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Energy Standards Working
Group
2 years
Tenaska, Inc.
2 years
First Wind
2 years
Developing the training and providing it while accommodating shift employees will require a substantial
amount of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
2 years
Time is needed to implement a training plan and revise it based on feedback from those being trained.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
2-3 years,
depending on
the extent of
equipment
involved and
size of facility.
Luminant
24 months
Prairie Power, Inc.
24 months
following
Regulatory
Approval
62
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Southern California Edison co.
Time
3yrs
Question 7b Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Duke Energy
Approximately
24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Kansas City Power & Light
N/A
The Generator Operator should be operating equipment within the Generator Interconnection Facility at the
direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
Public Utility District #1 of Clark
County
Twelve
months.
Clark’s generating operating personnel regularly engage in training however, to implement a Training
Program as rigorous as the TOP Training Program will take some time to complete.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Electric Market Policy
two years
Developing the training and providing it while accommodating shift employees will require a substantial
amount of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
63
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
c. The Generator Operator shall coordinate the operation of its Generator Interconnection Facility with the
Transmission Operator to whom it interconnects to preserve Interconnection reliability. (TOP-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7c Comment
Appears redundant with point e) below. There are already generator-outage reporting protocols in place.
This would be an unnecessary addition to existing processes.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
64
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
Luminant
18 months
South Carolina Electric and Gas
18 months
Prairie Power, Inc.
24 months
following
Regulatory
Approval
Southern California Edison co.
3yrs
Question 7c Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Less than 1
year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes. Additionally, the Generator Interconnection Facility is already considered to be part of the
Generating Facility and is likely already part of our existing compliance program.
65
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7c Comment
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No Time.
Clark believes the operation of its generator is already under the direction of its TOP and that coordination
has already occurred since the TOP has included the operation of Clark’s generator in its TOP-002 Normal
Operations Plan.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
66
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
d. The Transmission Operator has decision-making authority for the Generator Interconnection Operational
Interface. (TOP-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Pepco Holdings, Inc - Affiliates
Time
0-2 years
Question 7d Comment
Coordination is required for the TOP to notify the GO/GOP of the decisions being implemented.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
67
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
SERC Planning Standards
Subcommittee
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
18 months
South Carolina Electric and Gas
18 months
Southern California Edison co.
3yrs
Question 7d Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. Please see the response to question 8.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this because the Generator Interconnection Facility
is already considered to be part of the Generating Facility.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
68
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
Question 7d Comment
Clark believes that existing standards already grant the TOP decision-making authority for the Generator
Interconnection Operational Interface.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
69
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
e. The Generator Operator shall notify the Transmission Operator of a change in status of the Generation
Interconnection Facility.
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Pepco Holdings, Inc - Affiliates
Time
0-2 years
Question 7e Comment
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
70
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Luminant
18 months
Southern California Edison co.
3yrs
Question 7e Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
6 months.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
8 months
Duke Energy
Approximately
3 months
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
71
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Public Utility District #1 of Clark
County
Time
No time.
Question 7e Comment
Clark’s Generation Interconnection Facility status is already provided to the TOP in real time over the
TOP’s SCADA system.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
72
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
f. The Generator Operator shall operate the Generation Interconnection Facility within Facility Ratings. (TOP004)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
American Electric Power
Question 7f Comment
AEP does not believe that the added requirement is necessary as the Generator Interconnection Facility
should be adequately sized to handle the output of the generator.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions proposed in
this SAR are appropriate. Specific modifications will be determined by the SDT.
Bonneville Power Administration
0 months.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently operates within the facility ratings as required under FAC. If additional requirements are
instituted by NERC, there may be a need to have time to develop new programs and policies to comply with
additional requirements
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
12 months
73
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7f Comment
Subcommittee
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
18 months
South Carolina Electric and Gas
18 months
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
6 months
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
The Generator Interconnection Facility is already considered to be part of the Generator Unit and the facility
should be compliant currently with FAC standards.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
less than one
year
Facility should be compliant currently with FAC standards.
74
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7f Comment
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
The Generation Interconnection Facilities of Clark have ratings that exceed the maximum generating
capability of the interconnected generation facility.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
75
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
g. The Generator Operator shall disconnect the Generation Interconnection Facility immediately in coordination
with the Transmission Operator when time permits or as soon as practical thereafter if an overload or other
abnormal condition threatens equipment or personnel safety. (TOP-008)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7g Comment
In case of overload, the E.ON U.S. GOP has an overload current relay that already removes a generating
unit from the grid immediately. Moreover, it is expected that in most cases an Interconnection Agreement
between the generator and TO that it connects with already contains language supportive of this.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
76
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
36 months
Southern California Edison co.
3yrs
Question 7g Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
The Generator Interconnection Facility is already considered to be part of the Generator Unit. Expect that,
in most cases, the Interconnection Agreement between the generator and the TO or DP that it connects
with already contains language that supports this.
77
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7g Comment
Response: The SAR DT thanks you for your comment.
Electric Market Policy
less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
Clark has experienced no operating conditions where it had to disconnect the Generation Interconnection
Facility immediately due to an overload or other abnormal condition that threatened equipment or personnel
safety.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
78
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
8. If you have any other comments on this SAR or proposed standard revisions and NERC Glossary modifications
that you have not already provided in response to the prior questions, please provide them here.
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. Many of the comments were
addressed in earlier responses. Based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC
compliance filings, the SAR DT modified the SAR to give the SDT the flexibility to consider further modifications not identified in the Ad Hoc
Report. Finally, revisions to the SAR also allow the SDT the option of merging the changes into one new standard or into several different
existing standards.
Organization
Constellation Power Source
Generation Inc.
Question 8 Comment
Constellation would like to thank the Ad-Hoc group for the excellent work they did in creating the GOTO Final Report. In
particular, here are a few excerpts that Constellation agrees with, and would like the future SDT to consider:
oThe Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility.
oA Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator.
oAfter review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators, no
existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility.
Response: The SAR DT thanks you for your comments. The SAR DT supports the three concepts identified.
El Dorado Energy LLC
El Dorado Energy commends the efforts of the NERC Ad Hoc Group, and supports the Final Report from the Ad Hoc Group
for Generator Requirements at the Transmission Interface, and Standards Authorization Request addressing the various
Standards containing GO/GOP and TO/TOP Requirements. The Final Report and SARs are products of detailed analysis
and thoughtful consideration of the myriad issues surrounding the reliability implications of ownership and operation of
Generator Interconnection Facilities. It is noteworthy - though hardly surprising - that, after many months of study, the GO/TO
Task Force, a balanced group comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator interconnection facilities are
operated reliably. When implemented, the recommendations included in the Final Report and SARs should go a long way
toward providing the regulatory and compliance certainty needed by generators who own or operate Generator
Interconnection Facilities. Accordingly, El Dorado Energy encourages the Standards Drafting Team to act quickly to
implement the SARs.
79
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
Response: The SAR DT thanks you for your comment.
Competitive Power Ventures,
Inc.
Every effort should be made to precisely describe requirements that directly correspond to, and address, the reliability issues
framed by the GO/TO Ad Hoc Group. Particularly, "interconnection facilities" should be defined to account for and exclude
various transmission configurations on the generator side of the interconnection point that do not create network power flows
or otherwise operate as bona fide transmission systems.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
FAC-003 - Applicability apply to GIF above 200 kV that exceed two spans should be revised to "less than one-half mile" as
span lengths vary considerably. For example we have 3 spans over 1/4 mile.R1. requirement to "keep current, a formal
TVMP" should allow latitude for those entities with one-quarter mile of radial connecting transmission, all visible from the
office window, to have a less than a formal program, or at least a very SIMPLE program.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
First Wind
FAC-003 - Step 4.5 should be clearly identified as a “qualifier” for Generator Owner applicability. Although not the intent of
the standard, as currently drafted, the requirements apply to all Generator Owners. Additionally we recommend
modifications to address a disqualifier if the plant is located in an environment whose natural environment would prevent
vegetation from growing that could interfere with the reliability of the bulk Electric System. The following changes are
recommended.
4.4. Generator Owner.
4.5. This standard shall apply to the Generator Interconnection Facility above 200 kV that exceed two spans from the
generator property lineor are otherwise deemed critical by the Regional Entity below 200 kV (subject to the two-span
criteria.). This standard does not apply to all Generator Interconnection Facilities outside this threshold and those
facilities located in an area whose environment would prevent vegetation from growing.A generating facility located
underground, in the high desert or within a fully developed urban area where vegetation disturbances could not occur
should not be required to have a vegetation management program.
o MOD-010 - The changes made in this standard are not reflected in the associated standard, MOD-011 (possibly because
MOD-011 is not FERC approved).
o MOD-012 - The changes made in this standard are not reflected in the associated standard, MOD-013 (possibly because
MOD-013 is not FERC approved).
o PER-001 - The Purpose statement in the Standard needs to be modified to include GOP.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
o PER-002 - The Purpose statement in the Standard needs to be modified to include GOP.We recommend the addition of
PER-002 R3 is coordinated with the existing standard PRC-001 R1 to eliminate redundancy. While PER-002 R3 more clearly
calls for training, PRC-001 R1 implies training. The two standards should be combined into one training requirement.PRC001 R1 “Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar with the purpose and
limitations of protection system schemes applied in its area.”We recommend retiring PRC-001 R1 and modifying the
proposed standard PER-002 R3 as shown below:
Each Generator Operator shall implement an initial and continuing training program for all operating personnel that are
responsible for operating the Generator Protection System Equipment, including the Generator Interconnection Facility
that verifies the personnel’s ability and understanding to operate the equipment in a reliable manner.
o o TOP-002 - Requirement R14 contains sub-requirements R14.1 and R14.2 that were retired August, 1, 2007. Suggest
deleting the retired requirements with the proposed revision.
o TOP-004 - Requirement R7 has been added for the Generator Operator; however, the Generator Operation has not been
added to the Applicability.
o TOP-008 - The Purpose statement in the Standard needs to be modified to include GOP.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT.
California ISO
It does not appear that any of the Measures in the proposed Standards have been revised to reflect the new and/or revised
requirements.
Response: The SAR DT thanks you for your comment. The intent was to post just the initial set of proposed requirements to provide stakeholders with a sense of
the scope of the project. The SDT assigned to this project will need to work with stakeholders to develop not only the requirements, but all the other elements
needed to support those requirements, including measures, violation risk factors, time horizons, violation severity levels, evidence retention, etc.
North Carolina Electric
Membership Corporation
NCEMC is concerned with the decision to use “revisions to the latest versions of the following standards” that were included
in red-line format in this SAR: o BAL-005 o CIP-002 o EOP-001, -003, -004, -008 o FAC-001, -003, -008, -009 o IRO-005
o MOD-010, -012 o PER-001, -002 o PRC-001, -004, -005 o TOP-001, -002, -003, -004, -008 o VAR-001, -002
The use of these versions of the standards, many of which have been revised, approved by the NERC Board of Trustees and
filed with FERC emphasizes the flaw in a regulatory approval process that is not uniform throughout North America. Not all
registered entities are FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon NERC
Board of Trusteesapproval. Of the standards that are included in this SAR, three projects not including nterpretations have
been retired, modified, or new standards created that are now complied with by some registered entities. The projects
include; Project 2006-01 ― System Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 ― Cyber Security ― Order
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
706 ― CIP-002 through CIP-009. In addition, it is difficult to determine whether there is any coordination between the
activities of this SAR drafting team and those ofthe many existing drafting teams that are also revising standards. NCEMC
understands the dilemma of how to revise standards in a regulatory environment that has no defined time-line guidelines for
approval of standards upon filing with FERC, but reminds NERC, the Standards Committee and drafting teams that the
process must address the varying regulatory approval processes in NorthAmerica.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT. The SDT will work with the latest BOT approved versions of the
standards in support of your comment.
SERC Planning Standards
Subcommittee
No other comments
Kansas City Power & Light
No other comments.
South Carolina Electric and Gas
none
National Rural Electric
Cooperative Association
(NRECA)
NRECA is concerned with the decision to use “revisions to the latest versions of the following standards” that were included in
red-line format in this SAR: o BAL-005 o CIP-002 o EOP-001, -003, -004, -008 o FAC-001, -003, -008, -009 o IRO-005
o MOD-010, -012 o PER-001, -002 o PRC-001, -004, -005 o TOP-001, -002, -003, -004, -008 o VAR-001, -002The use
of these versions of the standards, many of which have been revised, approved by the NERC Board of Trustees and filed with
FERC emphasizes the flaw in a regulatory approval process that is not uniform throughout North America. Not all registered
entities are FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon NERC Board of
Trustees approval. Of the standards that are included in this SAR, three projects not including interpretations have been
retired, modified, or new standards created that are now complied with by some registered entities. The projects include;
Project 2006-01 ― System Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 ― Cyber Security ― Order
706 ― CIP-002 through CIP-009. In addition, it is difficult to determine whether there is any coordination between the
activities of this SAR drafting team and those of the many existing drafting teams that are also revising standards. NRECA
understands the dilemma of how to revise standards in a regulatory environment that has no defined time-line guidelines for
approval of standards upon filing with FERC, but reminds NERC, the Standards Committee and drafting teams that the
process must address the varying regulatory approval processes in North America.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT. The SDT will work with the latest BOT approved versions of the
standards in support of your comment.
Electric Market Policy
oEOP-003 - I do not understand the addition of GOP to this standard. Additionally, the Purpose statement is not in
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alignment with the additional GOP applicability.
oFAC-003 - Step 4.5 should be clearly identified as a “qualifier” for Generator Owner applicability. Although not the intent of
the standard, as currently drafted, the requirements apply to all Generator Owners.
oMOD-010 - The changes made in this standard are not reflected in the associated standard, MOD-011 (possibly because
MOD-011 is not FERC approved).
oMOD-012 - The changes made in this standard are not reflected in the associated standard, MOD-013 (possibly because
MOD-013 is not FERC approved).
oPER-001 - The Purpose statement is not in alignment with the additional GOP applicability.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT.
American Electric Power
Overall, AEP supports the concept of this SAR, but we question the number of new requirements that are being brought in
scope. Some of the requirements added appear to encourage this SAR to reach farther than the scope of addressing the
Generator Interconnection Facilities.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. The intent of the SAR was to collect feedback on the proposed scope of this
project.
Prairie Power, Inc.
PPI contends this SAR and associated requirement additions and revisions go well beyond the recommendations from the
Group needed to resolve the barrier issue between Transmission Operator and Generator Operator. The FAC-003 standard
revision, so that vegetation management can be enforced for transmission lines which interconnect generators to
transmission, is really all that is necessary. All these other changes just add confusion to already overlapped requirements.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. One of the goals of this project is to eliminate ‘overlaps’ so there is a clear
line of responsibility for each facility.
Southern California Edison co.
SCE believes that implementing changes type of changes proposed in 2010-07 should be looked at as a whole/ one entire
project rather than piece meal as alluded to in question number 7 of the comments form. As such, it is the company’s
position that approximately 3yrs is right amount of time to reliably implement the proposed revisions to the suite of standards
as identified in Project 2010-07. A 3 yr timeline would enable the project to be fully scoped out and budgeted, and allow for:
completion of the necessary engineering studies; design, procurement and construction of any new facilities necessitated by
the revisions; development of any new operations and communications procedures with respect to both the transmission and
generation facilities; and the training of personnel related to any new procedures.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard or an
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Question 8 Comment
existing standard(s). All timing issues related to the implementation plan will be addressed by the SDT. As envisioned, all requirements would become effective at the
same time as the proposed definitions to ensure that there are no gaps in the body of NERC requirements.
Sempra Generation
Sempra Generation commends the efforts of the NERC Ad Hoc Group, and supports the Final Report from the Ad Hoc Group
for Generator Requirements at the Transmission Interface, and Standards Authorization Request addressing the various
Standards containing GO/GOP and TO/TOP Requirements. The Final Report and SARs are products of detailed analysis
and thoughtful consideration of the myriad issues surrounding the reliability implications of ownership and operation of
Generator Interconnection Facilities. It is noteworthy - though hardly surprising - that, after many months of study, the GO/TO
Task Force, a balanced group comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator interconnection facilities are
operated reliably. When implemented, the recommendations included in the Final Report and SARs should go a long way
toward providing the regulatory and compliance certainty needed by generators who own or operate Generator
Interconnection Facilities. Accordingly, Sempra Generation encourages the Standards Drafting Team to act quickly to
implement the SARs.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
AmerenUE, Power Operations
Services
The items in Question #7 illustrate the need for a written Agreement or Procedure between the GO, GOP, TO and TOP on
how to comply with these new, and modified, Requirements. An Agreement or Procedure would provide the certainty of:
o Assignable and measurable responsibilities,
o Mutual agreement on specific actions, and
o Implementation deadlines.
Without such an Agreement or Procedure, there will be no auditable commitment to defined specific actions, predetermined
responsibilities and closure of the reliability gap in total.
Response: The SAR DT thanks you for your comment. The SDT will discuss these kinds of issues, but such agreements are covered by the NERC Rules of
Procedures and it is outside the scope of both the SAR DT and the SDT to propose changes to the NERC Rules of Procedure.
ERCOT ISO
The proposed language in Requirements 9 and 10 (hereafter R9 and R10) for NERC Standard TOP-001-X, Reliability
Responsibilities and Authorities, clouds the responsibilities among different functional entities that are and are not held
accountable to this Standard. Specifically, the first part of the sentence in R9 states: “The Generator Operator, in accord with
the expectations defined by the Transmission Operator, shall coordinate...” This statement is overly broad and vague. For
instance, is the statement meant to refer to Interconnection Agreements that have been entered into between Generator
Operators and Transmission Operators? Or, is the statement intended to include other agreements as well? In addition, there
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are items listed in R9 (i.e., switching elements, outage planning, and real-time and anticipated emergency conditions) which
are normally the responsibilities of the Transmission Owner and/or the Reliability Coordinator; however, NERC Standard
TOP-001-X is not applicable to the Transmission Owner or the Reliability Coordinator. Also, the item “other conditions
mutually agreed-upon by the Generator Operator and Transmission Operator” is vague and ambiguous and should be
clarified in order not to confuse tasks that may be more aligned with the responsibilities of the Transmission Owner or the
Reliability Coordinator. Furthermore, R9 and R10 strongly imply and explicitly give the Transmission Operator authority to
take action “in order to preserve Interconnection reliability.” This type of wide-area authority is meant to describe Reliability
Coordinator-related obligations. The NERC Function Reliability Model is clear in defining the function and tasks of reliability
operations. The Reliability Coordinator is responsible, in concert with other Reliability Coordinators, for the Interconnection as
a whole; not the Transmission Operator. Lastly, it is unclear how an entity registered for multiple functions (for example,
Reliability Coordinator and Transmission Operator) would be held accountable under this NERC Standard. If the intent is that
R9 and R10 are to be the obligations only of those functional entities for which the NERC Standard is applicable, then the
language in the NERC Standard should clearly state that intent.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. As envisioned, the SDT will coordinate its work with the Functional Model
Working Group to ensure that any new functional entities are identified with a clear definition, and a clear scope of responsibilities and tasks.
PSEG Companies
The PSEG Companies support this approach to ensure that all components of the BES are adequately covered by the
reliability standards. The drafting team has done a good job of identifying the appropriate areas of concern.
Response: The SAR DT thanks you for your comment.
Transmission Owner/Generation
Owner
The SAR for Project 2010-07 proposes a number of specific changes to existing Reliability Standards based on the GOTO
Report. FPL believes that identifying the exact standards and language for revision should be the purview of a Standards
Drafting Team and not embedded within the SAR itself. The Standards Drafting Team should be empowered to review the
GOTO Report and make independent recommendations. Many of the questions contained in this SAR comment form are
more appropriate for a Standard’s drafting comment form and not for a SAR. The place to discuss and evaluate specific
wording changes as applicable to standards revisions should be contained in the Standard Drafting process. The SAR should
lay the foundation for the need for changes, not disseminate or debate exact changes.FPL would recommend that the
sections “Brief” and “Detailed Description” of the SAR should be amended as follows: “Taking into consideration the GOTO
Final Report from November 2009, the need for revisions to existing standards may exist. The Standards Drafting Team will
evaluate the recommendations of the GOTO Final Report and recommend changes as necessary.”
Response: The SAR DT thanks you for your comment and agrees. The SAR DT has assembled the specific suggestions for revisions to definitions and
requirements provided in response to this SAR. As envisioned, the SDT will consider those comments. Note that the SAR has been modified to give the SDT the
flexibility to address this concern.
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Northeast Power Coordinating
Council
Question 8 Comment
The term “two spans” is used in the Introductory Section of this Comment Form (Conclusions Item 6, Recommendations Item
3), and will need a clear, and specific definition. “Generally” is not a word to be used in a definition.
Response: The SAR DT thanks you for your comments.They will be referred to the SDT.
Xcel Energy
There are many other standards development projects underway that are modifying the same standard. It is unclear as to
how the changes will be coordinated amongst the many teams.
Xcel Energy
There are many other standards development projects underway that are modifying the same standard. It is unclear as to
how the changes will be coordinated amongst the many teams.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. As envisioned, the SDT will work with the latest BOT approved versions of
the standards and will coordinate its work with all other SDTs that are actively working on the same standards.
ISO RTO Council Standards
Review Committee
These SAR and associated draft standards changes go beyond what is needed to resolve the GO/TO GOP/TOP registration
issue. The only real changes that are needed are to include adding GO and GOP applicability in the FAC-003 standard so
that vegetation management can be enforced for lines built to interconnect generators without registering the GO/GOP as a
TO/TOP. All additional changes just add confusion and cause significant coordination issues with other draft standard
changes.This proposed SAR and associated standards’ modifications does not appear to have been coordinated with any
other drafting team. There are many standards and requirements that are in various states of change. For instance, the TOP
standards have been significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Midwest ISO Standards
Collaborators
These SAR and associated draft standards changes go beyond what is needed to resolve the GO/TO GOP/TOP registration
issue. The only real changes that are needed are to include adding GO and GOP applicability in the FAC-003 standard so
that vegetation management can be enforced for lines built to interconnect generators without registering the GO/GOP as a
TO/TOP. All additional changes just add confusion and cause significant coordination issues with other draft standard
changes.This proposed SAR and associated standards’ modifications does not appear to have been coordinated with any
other drafting team. There are many standards and requirements that are in various states of change. For instance, the TOP
standards have been significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. The purpose of this SAR was to seek stakeholder views on the scope of
requirements that may need modification, and most stakeholders who participated in this comment period support modifications that go beyond modifying only the
Transmission Vegetation Management standard.
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E.ON U.S.
Question 8 Comment
This SAR should only apply to those separate entity GOPs that already adhere to an OATT. Those GOPs should be required
to register additionally as a TO/TOP. This should not apply to a GOP within a Corporation that includes TO/TOP that adhere
to an OATT, and have already defined an internal division of responsibilities for the Transmission Interface between the GOP
and TOP.
Response: Based on a review of the full body of industry comments, we believe that there is a reliability need for this SAR. Further, registration issues are outside
the scope of the SAR DT.
Energy Standards Working
Group
We commend the work of the team that produced the report and this SAR and suggest that the Standard Drafting Team give
due deference to the report with the modifications that we have suggested in questions 4 and 5 above.In addition, EPSA
would highlight the following conclusions that follow from the report:
oThe Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility
oA Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator
oAfter review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators, no
existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility
Response: The SAR DT thanks you for your comment. The SAR DT agrees with your conclusions.
Tenaska, Inc.
We commend the work of the team that produced the report and this SAR and suggest that the Standard Drafting Team give
due deference to the report with the modifications that we have suggested in questions 4 and 5 above.In addition, we would
highlight the following conclusions that follow from the report:
o The Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility
o A Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator
o After review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators,
no existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility
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Response: The SAR DT thanks you for your comment. The SAR DT agrees with your conclusions.
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Informal Comments on White Paper for Project 2010-07—Generator Requirements at the
Transmission Interface
The Project 2010-07—Generator Requirements at the Transmission Interface standard drafting team
(drafting team) thanks all who provided comments during this stage of development. The White Paper
Proposal for Informal Comment was posted for a 30-day informal public comment period from March 4,
2011 through April 4, 2011. The stakeholders were asked to provide feedback via email to the NERC
Project Coordinator. 51 sets of comments were submitted.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
The SDT has completed the review of the informal comments from industry for Project 2010-07—
Generator Requirements at the Transmission Interface. Each comment was reviewed and considered by
the drafting team as it proposed modifications to FAC-001 and FAC-003 and developed the project’s
background document, and it will continue to consider this stakeholder feedback as the project
progresses. If a comment is not specifically addressed, it is likely because the drafting team has
addressed it elsewhere or the comment did not add clarity or otherwise improve the quality of the
proposed standards.
A majority of commenters supported the concepts in the white paper, which represent a focused but
comprehensive approach to including responsibility for generator interconnection Facilities in NERC’s
Reliability Standards. Most commenters agreed that the approach of developing specific changes to a
limited number of standards was preferable to developing new definitions or revising existing
definitions.
The drafting team received many comments on the general direction of the project:
•
•
•
Some suggested that an interim solution be implemented until the modified standards are
approved. The drafting team is providing input to NERC compliance staff upon request as it
works toward an interim solution.
Some said that Generator Owners and Generator Operators that are radial in nature should
not have to comply with any additional standards. In this phase of the project, the drafting
team’s goal was to identify and modify standards necessary to eliminate any reliability gaps
related to extended generation interconnection Facilities. Ultimately, this shall prevent the
registration of Generator Owners and Generator Operators as Transmission Owners and
Transmission Operators. After review of all of the standards, the drafting team believes that it is
appropriate to apply FAC-001 and FAC-003 to Generator Owners (in certain cases). This was
confirmed by stakeholder comments during the informal comment period.
Some were concerned with the drafting team’s use the term “transmission” to label generator
interconnection Facilities. Several commenters were concerned with the use of “transmission
lines” as a label for generator interconnection Facilities. While such a label has been applied in
other contexts by certain entities, the drafting team has avoided that labeling in its
modifications to FAC-001 and FAC-003 and its background documents.
•
•
•
•
Some were concerned that the white paper did not acknowledge interface agreements. The
drafting team recognizes that interface/interconnection agreements usually have explicit
language about coordination between Generator Owners and Operators and Transmission
Owners and Operators, but unfortunately these agreements are not viewed by regulatory
authorities as a tool that can be used for meeting reliability standards.
Some encouraged the SDT to revisit certain standards that already apply to Generator Owners
and Generator Operators because some standards split requirements by applicable entity. The
drafting team has reviewed the standards that already include Generator Owners and Generator
Operators and determined that no changes to specific requirements are necessary. The drafting
team attempted to better explain its rationale in these cases in the latest version of the
background document.
Several addressed commercial issues in their comments on the white paper. Such comments
are outside the scope of this drafting team (and NERC Reliability Standards in general) and thus
have not been addressed here.
Some pointed out reference errors in the white paper. The drafting team is grateful for these
comments and has attempted to remedy all errors in the resource document that has evolved
from the white paper.
The drafting team received no comments indicating that it should have included standards other than
the two identified (FAC-001 and FAC-003), but several commenters suggested modifications to the
proposed approaches to FAC-001 and FAC-003.
A number of comments stated that the “trigger” for the application of FAC-001 should not be the receipt
of a request, but rather should be based upon “the intent or obligation” to interconnect a new Facility to
an existing interconnecting Facility that is owned by a generator. Accordingly, the drafting team has
proposed language to address this concern. The intent of this modified language is to start the
compliance clock when the generator Facility owner executes an Agreement to perform the reliability
assessment required in FAC-002. This step should occur whether the generator voluntarily agrees to the
interconnection request or is compelled by a regulatory body to do so. In either case, we expect the
Generator Owner and the requestor to execute some form of an Agreement. The drafting team
intentionally excluded a specific reference to the kind of Agreement (such as a feasibility study) in
deference to comments that we should avoid comingling of commercial and reliability aspects in
reliability standards.
Similarly, a majority of comments supported FAC-003 applicability to the Generator Owner but
suggested some exclusion for a “short length” Facility. Accordingly, we modified the language to apply
only to a Facility that extends at least ½ mile beyond the fenced boundary(ies) of the switchyard,
generating station, or generating substation.
In addition to the majority of comments addressing the line length issue, the drafting team received
some minority comments on FAC-003:
•
•
•
•
Some indicated that Generator Owners should not be added to FAC-003 because they are
never an IROL circuit. FAC-003 addresses circuits other than those associated with an IROL.
Some stated that changing FAC-003 would do nothing to prevent adverse reliability impacts,
because a radial line can’t cascade. The drafting team believes there is a reliability-related need
to apply FAC-003 to GOs with extended interconnection Facilities.
One commenter suggested a better connection between FAC-003 and FAC-014, stating that
there is nothing in either standard where the Planning Coordinator is informing the
Transmission Owners and Generator Owners of the applicability of their Facilities as outlined
in the Facilities section 4.2.2 of FAC-003. FAC-014-2 R5 addresses this issue.
One commenter suggested that the requirement simply be that the Generator Owner
coordinates with the Transmission Owner to ensure that the generator interconnection
Facilities are included. The drafting team believes there is a reliability-related need to apply
FAC-003 to Generator Owners with extended interconnection Facilities. An entity always has the
opportunity to enter into a JRO where appropriate.
A majority of commenters also supported the drafting team’s proposal to not adopt new defined terms.
But many commenters said that if the new terms were not adopted, the drafting team needed to work
to address registration issues related to Generator Owners and Generator Operators, especially those
with ownership/operational responsibility for the Facility that interconnects the generator(s) to the
Transmission Owner’s Facility. A few stated that there needed to be a clearer delineation of
responsibilities between the Generator Owner and Transmission Owner and the Generator Operator
and Transmission Operator where ownership and operational responsibility of an interconnection
Facility wasn’t clearly understood. While the drafting team agrees with some of the comments, it is not
empowered to make all changes which may be necessary to alleviate the concerns expressed in the
comments.
However, during this process, the drafting team has been meeting with NERC and FERC staffs, regional
compliance managers, and industry organizations to discuss possible solutions to the issue of concern to
most Generator Owner/Generator Operators (e.g., registration as a Transmission Owner/Transmission
Operator). The drafting team believes this issue, and the related concerns, have the attention of
appropriate NERC and regional staffs and has volunteered to provide assistance in their efforts to
address them.
The goal of the Project 2010-07 drafting team is to work with NERC and regional compliance
enforcement and compliance registration staffs to develop a comprehensive package that will address
all reliability gaps, whether real or perceived, so that entities are appropriately registered and the
appropriate reliability standards are applied to those entities.
**Note about comments from February and March 2010 SAR Posting**
During its review of these comments, the drafting team also returned to comments from its SAR posting
in February and March of 2010, as many of the comments on the SAR posting dealt with the proposals in
the original Ad Hoc Group for Generator Requirements at the Transmission Interface’s Final Report. In
returning to these comments, the drafting team confirmed that it had addressed all relevant comments.
Because of the narrower focus of the current Project 2010-07, many comments (such as those on the Ad
Hoc Group’s proposed definitions) were no longer relevant, but all others have been addressed:
•
•
•
•
Need to align project with compliance responsibility: The drafting team is working with NERC
and regional compliance staffs on exactly this.
The scope of the project is too broad: The scope has been narrowed.
The project needs further clarification: The original white paper posted for informal comment
was developed to provide further clarification on the project. That white paper has been
modified to be used as a background resource document.
The standards changes should be implemented all at once: With only two standard changes
being implemented and an interim solution being developed by NERC’s compliance staff (in
coordination with Regional compliance staff), the drafting team is not as concerned with
implementing the changes simultaneously. If, for instance, FAC-001 changes are implemented
before FAC-003 changes, the interim compliance solution will remain in effect until FAC-003
changes are also implemented to ensure that there are no gaps during the implementation
periods.
The drafting team thanks all those who participated in the original SAR posting; the comments from that
posting were invaluable during the transition from ad hoc group to standard drafting team.
Consideration of Comments on Generator
Requirements at the Transmission Interface – Project 2010-07
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments on the first formal posting for Project 2010-07—Generator Requirements at the
Transmission Interface. These standards were posted for a 30-day public comment period from June
17, 2011 through July 17, 2011. The stakeholders were asked to provide feedback on the standards
through a special Electronic Comment Form. There were 43 sets of comments, including comments
from approximately 143 different people from approximately 100 companies representing 9 of the 10
Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
The SDT thanks all stakeholders who provided comments. Your feedback helped the drafting team
further modify its proposed standard changes, and the team believes that the changes are clearer and
more technically sound because of it.
The SDT made a few substantive changes to both FAC-001 and both versions of FAC-003. With respect
to FAC-001, many commenters suggested changes to both R2 and R3 to add clarity. The “activation”
language in R2 now reads “…within 45 days of having an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System…” R3 has been modified so that it is clearer that only
Generator Owners applicable in accordance with R2 are required to comply, and the word “protection”
in R3.1.5 has been made lowercase. Per stakeholder comments, the SDT also removed the Generator
Owner from R4, because they agree that that inclusion was redundant to language in R2. Because
Generator Owners have been removed from the requirement (and thus the requirement is no longer
within the SDT’s scope), the SDT reverted back to the original requirement language in the approved
version of the standard.
Some commenters were still concerned with the 45 day “activation” point, and indicated that more
time could be needed for compliance. The SDT reminded these commenters that the 45 day timeframe
is 45 days from the time the entity has a study Agreement, not 45 days to execute the Agreement
altogether. Any commenters who were concerned that their Facilities could never receive an
interconnection request were reminded that if that’s the case, this standard would never apply to
them. And those commenters who insisted that Generator Owners could never receive a request for
interconnection were reminded that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC
¶ 61,064 at P. 13), Generator Owners have received or have been directed to execute interconnection
requests for their Facilities. Thus, the SDT thinks it is important to clarify the responsibilities related to
such a request in NERC’s Reliability Standards.
With respect to FAC-003, many commenters focused on the half-mile qualifier in both versions of the
standard. Some commenters found the half-mile length too short, others found it too long, and still
others found the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its latest
proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the
fenced area of the generating station switchyard…” The SDT believes that the one mile length is a
reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator
Owner or an auditor. Finally, the team maintains that it is appropriate to include this qualifier for
Generator Owners because there is a very low risk from vegetation within the line of sight, and thus
the formal steps in this standard are not necessary to ensure reliability of these lines.
The majority of commenters did not suggest the addition of any standards or requirements to the
team’s scope of work, and a few commenters cautioned strongly against any additions. Some
commenters suggested that the team consider including those standards and requirements listed in
the June 2011 Cedar Creek and Milford FERC orders. The drafting team has considered the inclusion of
the requirements listed in the Cedar Creek and Milford orders in the past, and we have been revisiting
them throughout our process. We continue to conclude, with stakeholder support, that no additional
substantive standard or requirement changes are necessary to achieve the goal of this project. With
this posting, the drafting team has revisited those standards yet again and developed a comprehensive
document and spreadsheet tracing our rationale (at every stage of the process) for not including
additional standards or requirements. The team has elected to propose a slight clarifying change in
PRC-004-2, but no changes to the applicability of that or any other standard.
While the drafting team will not be adding standards at this time because they do not believe such
additions are technically justified or justified by stakeholder comments, the SDT will be seeking some
additional informal feedback from industry groups to ensure that their technical justifications are
sound and supported by others outside of the drafting team. The current draft documents showing the
team’s rationale and technical justification for including/excluding standards for revision under this
project have been posted for information on the project page with this posting. If you have any specific
feedback on these documents, you are welcome to email mallory.huggins@nerc.net.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf .
Project 2010-07 Consideration of Comments
2
Index to Questions, Comments, and Responses
1.
Do you support the proposed redline changes to FAC-001-1? .................................. 11
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1?.................................................................... 28
3.
Taking into consideration that only one of the versions of FAC-003 will actually be
implemented, a decision that will be made as the Project 2010-07 drafting team learns more
about the status of Project 2007-07—Vegetation Management, do you support the proposed
redline changes to FAC-003-X and FAC-003-3? ..................................................... 33
4.
The drafting team has added Generator Owners to the Applicability sections of FAC-003-X and
FAC-003-3 with the qualifier that the included lines “extend greater than one half mile beyond
the fenced area of the switchyard, generating station or generating substation up to the point
of interconnection with the Transmission system.” The team received many comments about
the need to define a distance rather than other measures for exclusion, and decided on the
one half mile as a reasonable distance. Do you agree with this half-mile qualifier? ..... 43
5.
Do you support the two year compliance timeframe for Generator Owners as included and
explained in the Implementation Plans for FAC-003-X and FAC-003-3?..................... 53
6.
In its background resource document, the drafting team lists the standards that it has not
modified, and offers rationale for its decisions. Are there any reliability standards or
requirements that you believe should apply to Generator Owners or Generator Operators that
own and are responsible for the operation of an overhead Facility, that are not already
applicable or have been proposed to be applicable (FAC-001 and FAC-003) by the Project
2010-07 drafting team? If so, please list them and offer an explanation as to why they should
be applicable to that entity. ................................................................................ 57
7.
Do you have any other questions or concerns with the proposed standards or with the
background resource document that have not been addressed? If yes, please explain.63
Project 2010-07 Consideration of Comments
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Notheast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Gregory Campoli
New York Independent System Operator
NPCC 2
3.
Kurtis Chong
Independent Electricity System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
7.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
8.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9.
Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
NPCC 10
10. Kathleen Goodman ISO - New England
NPCC 2
11. Chantel Haswell
FPL Group, Inc.
NPCC 5
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
2.
Gerald Beckerle
Group
SERC OC Standards Review Group
X
2
3
4
5
6
7
8
9
X
Additional Member Additional Organization Region Segment Selection
1.
Scott Brame
NCEMC
SERC
1, 3, 5, 9
2.
Dan Roethemeyer
Dynegy
SERC
4, 5, 6
3.
Jeff Harrison
AECI
SERC
1, 3, 5
4.
Scott McGough
OPC
SERC
5
5.
Alisha Ankar
Prairie Power
SERC
3, 5
6.
Robert Thomasson Big Rivers
SERC
1, 3, 5, 9
7.
Bob Dalrymple
TVA
SERC
1, 3, 5, 9
8.
Dale Donmoyer
Calpine
SERC
5
9.
Richard Dearman
TVA
SERC
1, 3, 5, 9
10. Andy Burch
EEI
SERC
1, 5
11. Eugene Warnecke
Ameren
SERC
1, 3
12. Gene Delk
SCE&G
SERC
1, 3, 5
13. Larry Rodriquez
Entegra
SERC
5
14. Randy Hubbert
Southern
SERC
1, 3, 5
15. Jim Viikinsalo
Southern
SERC
1, 3, 5
16. Marc Butts
Southern
SERC
1, 3, 5
17. Ken Parker
Entegra
SERC
5
18. Bill Autrey
Alabama Power
SERC
1, 3, 5
19. Melvin Roland
Southern
SERC
1, 3, 5
20. Mike McCollum
OPC
SERC
5
21. Mike Hirst
Cogentrix
SERC
5, 6
Project 2010-07 Consideration of Comments
5
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
22. William Berry
OMU
SERC
1, 3, 5
23. Brent Davis
Entergy
SERC
1, 3
24. Brad Young
LGE/KU
SERC
1, 3, 5
25. Wes Davis
SERC
SERC
10
3.
Group
Additional Member
Midwest Reliability Organization's NERC
Standards Review Forum (NSRF)
Carol Gerou
Additional Organization
X
3
X
4
X
5
6
X
X
X
X
7
8
9
Region Segment Selection
1.
Mahmood Safi
Omaha Public Power Dist
MRO
1, 3, 5, 6
2.
Chuck Lawrence
American Transmission Company
MRO
1
3.
Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4.
Jodi Jenson
Western Area Power Administration
MRO
1, 6
5.
Ken Goldsmith
Alliant Energy
MRO
4
6.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
7.
Dave Rudolph
Basin Electric Power Copperative
MRO
1, 3, 5, 6
8.
Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9.
Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
10. Joseph DePoorter
Madison Gas and Electric Company
MRO
3, 4, 5, 6
11. Scott Nichols
Rochester Public Utilities
MRO
4
12. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
13. Richard Burt
Minnkota Power Copperative
MRO
1, 3, 5, 6
14. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
15. Scott Bos
Muscatine Power and Water
MRO
3, 4, 5, 6
16. Lee Kittleson
Otter Tail Power Company
MRO
5, 1, 3, 6
17. Marie Knox
Midwest ISO
MRO
2
4.
Connie Lowe
Group
X
2
Electric Market Policy
X
X
Additional Member Additional Organization Region Segment Selection
1. Mike Crowley
SERC
1
2. Louis Slade
RFC
5, 6
3. Michael Gildea
NPCC 5, 6
4. Mike Garton
MRO
Project 2010-07 Consideration of Comments
5, 6
6
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
Group
Additional Member
Charles W. Long
SERC Planning Standards Subcommittee
Additional Organization
Ameren Services Co.
SERC
1
2. James Manning
NC Electric Membership Corp. SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Pat Huntley
SERC Reliability Corp.
SERC
10
5. Bob Jones
Southern Company Services
SERC
1
Group
3
4
5
6
7
8
9
X
Jesus Sammy Alcaraz
Imperial Irrigation District (IID)
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Tino Zaragoza
IID
WECC 1
2. Jesus Sammy Alcaraz IID
WECC 3
3. Diana Torres
IID
WECC 4
4. Marcela Caballero
IID
WECC 5
5. Cathy Bretz
IID
WECC 6
7.
Group
Brent Ingebrigtson
No additional members listed.
LG&E and KU Energy
X
X
X
X
8.
Public Service Enterprise Group
X
X
X
X
Group
John Seelke
Additional Member Additional Organization Region Segment Selection
1. Ken Brown
PSE&G
RFC
1, 3
2. Clint Bogan
PSEG Fossil
RFC
5
3. Peter Dolan
PSEG ER&T
RFC
6
4. Scott Slickers
PSEG Fossil
NPCC
5
5. Eric Schmidt
PSEG ER&T
NPCC
6
6. Mikhail Falkovich
PSEG Fossil
ERCOT 5
9.
Group
SPP Reliability Standards Development
Team
Jonathan Hayes
X
Additional Member Additional Organization Region Segment Selection
1. Valerie Pinamonti
AEP
SPP
1, 3, 5
2. Newton Alan Ward
AEP
SPP
1, 3, 5
Project 2010-07 Consideration of Comments
10
X
Region Segment Selection
1. John Sullivan
6.
2
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Mahmood Safi
OPPD
SPP
1, 3, 5
4. John Allen
SPRM
SPP
1, 4
5. Mitch Williams
Western Farmers
SPP
1, 3, 5
6. Robert Cox
Lee County Electric
7. Don Reinert
Westar
SPP
1, 3, 5, 6
8. Robert Rhodes
SPP
SPP
2
10.
Group
Additional Organization
PPL Supply Group
Leland McMillan
PPL Montana, LLC
2.
Don Lock
Lower Mount Bethel Energy, LLC RFC
5
3.
PPL Brunner Island, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Martins Creek, LLC
RFC
5
6.
PPL Montour, LLC
RFC
5
Mark Heimbach
PPL EnergyPlus, LLC
MRO
6
PPL EnergyPlus, LLC
NPCC
6
9.
PPL EnergyPlus, LLC
RFC
6
10.
PPL EnergyPlus, LLC
SERC
6
11.
PPL EnergyPlus, LLC
SPP
6
12. John Cummings
PPL EnergyPlus, LLC
WECC 6
11.
Jason Marshall
Additional Member
5
6
7
8
9
Additional Organization
X
ACES Power Members
X
Region Segment Selection
1. Darin Adams
East Kentucky Power Cooperative SERC
1, 3, 5
2. Susan Sosbe
Wabash Valley Power Association RFC
3
3. Mohan Sachdeva
Buckeye Power
3, 5
RFC
12.
Individual
Chris Higgins
Bonneville Power Administration
13.
Individual
Jack Cashin
EPSA
14.
Individual
Sandra Shaffer
PacifiCorp
X
15.
Individual
Janet Smith, Regulatory
Arizona Public Service Company
X
Project 2010-07 Consideration of Comments
X
WECC 5
8.
Group
4
Region Segment Selection
1.
7.
3
NA
Annette Bannon
Additional Member
2
X
X
X
X
X
X
X
X
X
X
X
X
8
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
Affairs Supervisor
16.
Individual
Bo Jones
Westar Energy
17.
Individual
Antonio Grayson
Southern Company
X
18.
Individual
Mike Laney
Luminant Power
X
19.
Individual
Thad Ness
American Electric Power
X
X
X
20.
Individual
Edward Cambridge
APS
X
X
X
21.
Individual
Gretchen Schott
BP Wind Energy North America Inc.
Individual
23. Individual
Katy Mirr
Brian Evans-Mongeon
Sempra Generation
Utility Services, Inc.
24.
Individual
Samuel Reed
Tri-State Generation and Transmission, Inc.
X
25.
Individual
Alice Ireland
Xcel Energy
X
26.
27.
Individual
Individual
Jody Nelson
Bill Rees
Georgia Transmission Corporation
BGE
X
X
28.
Individual
John Bee
Exelom
X
29.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
30.
Individual
Dale Fredrickson
Wisconsin Electric
Individual
32. Individual
Keith Morisette
Joe Petaski
Tacoma Power
Manitoba Hydro
33.
Individual
Greg Rowland
Duke Energy
34.
Individual
Amir Hammad
Constellation Power Generation
Individual
36. Individual
Kirit Shah
Rex Roehl
Ameren
Indeck Energy Services
X
X
X
X
37.
Individual
Chad Bowman
CHPD
X
X
X
38.
Individual
Andrew Z Pusztai
American Transmission Company
X
39.
Individual
Michael Falvo
Independent Electricity System Operator
22.
31.
35.
Project 2010-07 Consideration of Comments
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
40.
Individual
Doug Hohlbaugh
FirstEnergy Corp
X
Individual
42. Individual
Sandy O'Connor
X
Natalie McIntire
TransAlta Centralia Generation LLC
American Wind Energy Association
43.
Donald Brookhyser
Cogeneration Association of California
41.
Individual
Project 2010-07 Consideration of Comments
2
3
X
4
X
5
X
6
7
8
9
X
X
10
10
1. Do you support the proposed redline changes to FAC-001-1?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-001, and and the team has made additional changes,
based on commenter feedback, where they believe those changes add clarity.
Commenters suggested changes to both R2 and R3 to add clarity. The “activation” language in R2 now reads
“…within 45 days of having an executed Agreement to evaluate the reliability impact of interconnecting a third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to the Transmission System…” R3 has
been modified so that it is clearer that only Generator Owners applicable in accordance with R2 are required to
comply, and the word “protection” in R3.1.5 has been made lowercase. Per stakeholder comments, the SDT also
removed the maintenance requirements for the Generator Owner from R2, and the Generator Owner from R4
altogether. Because Generator Owners have been removed from the requirement (and thus the requirement is no
longer within the SDT’s scope), the SDT reverted back to the original requirement language in the approved version
of the standard.
Some commenters were still concerned with the 45 day “activation” point, and indicated that more time could be
needed for compliance. The SDT reminded these commenters that the 45 day timeframe is 45 days from the time
the entity has a study Agreement, not 45 days to execute the Agreement altogether. Any commenters who were
concerned that their Facilities could never receive an interconnection request were reminded that if they are correct,
this standard would not apply to them. Those commenters who insisted that Generator Owners could never receive a
request for interconnection were reminded that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC
¶ 61,064 at P. 13), Generator Owners have received or have been directed to execute interconnection requests for
their Facilities. Thus, the SDT believes it is important to clarify the responsibilities related to such a request in NERC’s
Reliability Standards.
Some commenters brought up tariff-related issues. While the SDT has made changes attempting to clarify what was
perceived by some commenters to be ambiguous qualifying language in R2, and while the commenters are correct
that a valid interconnection would likely need to go through the generator interconnection process under its
applicable tariff, it would be inappropriate for any market- or tariff-related language to be included in a NERC
Reliability Standard. The goal of the drafting team was simply to clarify a Generator Owner’s obligations, under
NERC’s Reliability Standards, for handling an interconnection request and the related interconnection requirements.
Several commenters also suggested changes to VRFs and VSLs. Because the SDT did not make any substantive
changes to R1 or R4, the team only made changes to the VSLs or VRFs if we were correcting a typo; anything
substantive would be outside the scope of this SDT. In the case of R2 and R3, changes were made per commenter
suggestions.
Finally, the formatting error in the Applicability section has been corrected.
Project 2010-07 Consideration of Comments
11
For a more detailed explanation of the team’s rationale, please see the accompanying FAC-001-1 technical
justification.
Organization
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes or No
Question 1 Comment
No
In general, the NSRF supports the changes to FAC-001-1. However the 45 days to execute an
agreement would be a significant burden on a Generator Operator that does not have an
existing process in place. The NSRF believes an aggressive but realistic time frame is 120 days.
This would allow sufficient time to develop the procedure and obtain the necessary technical
and legal reviews.
Please clarify why "Protection" is capitalized in section 3.1.5. "Protection System" is defined by
NERC but "System Protection" is not.
Recommend the "half mile" statement be included within the Applicability section of this
Standard as it stated in FAC-003-X.
Response: Thank you for your comment. The team proposed 45 days from the time the entity has a study Agreement, not 45 days to
execute the Agreement altogether. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of
the team’s rationale for using that time frame. No change made.
“Protection” in 3.1.5 has been made lowercase.
With respect to the “half mile” comment, an entity could receive an interconnection request for its interconnection Facility at any point along
that Facility. An exemption or exclusion based on the length of the Facility is not justified because doing so would create a reliability gap. No
change made.
Public Service Enterprise
Group
No
The language in R2 needs to be clarified with regards to the term “its existing generation
Facility.” The interconnection leads are considered part of the “existing generation Facility,”
but so are the generator, generator step-up transformer and other equipment associated with
the generator. The project Background Resource Document (p.2) makes it clear that the
interconnection to an existing generator facility is contemplated to be to the “existing
interconnecting Facility that is owned by a generator” - i.e., the generator’s interconnection
leads. We propose that the term “its existing generation Facility” be replaced with “the
Generator Owner’s existing interconnecting transmission Facility.”
Response: Thank you for your comment. We agree that some additional specification could be useful, and we have used the suggested
Project 2010-07 Consideration of Comments
12
Organization
Yes or No
Question 1 Comment
clarifying language.
SPP Reliability Standards
Development Team
No
We are concerned that some of the language is ambiguous. We would like to be clear that
placing new requirements on Generator Owners that are already in place and have been in
place under FERC policy is inaccurate. We want to make sure that regardless of what the
generator tie line is classified as, that a valid interconnection would go through the Generator
Interconnection process under its applicable tariff.
Format error in 2.4.1 should read 4.2.1 in applicability.
We would like to see more definition in applicability section 4.2. How does the Generator
Owner get involved in this process?
The VRF for R4 is listed as a medium and appears to us as an administrative requirement. We
would recommend that the VRF be changed to low.
The moderate and high VSL for R1 seems to be duplicative. We would recommend taking a
second look and would recommend that the high should be that “if you failed to do two of the
following”.
We would recommend that the VSL on R4 read: “The responsible entity failed to make the
requirements available within 30 business days after a request.”
Response: Thank you for your comment. We have attempted to clarify what was perceived by some commenters to be ambiguous qualifying
language. You are correct that a valid interconnection would likely need to go through the generator interconnection process under its
applicable tariff, but it would be inappropriate for any market- or tariff-related language to be included in a NERC Reliability Standard. The
goal of the drafting team was simply to clarify a Generator Owner’s obligations, under NERC’s Reliability Standards, for handling an
interconnection request and the related interconnection requirements.
The format error in the applicability section has been corrected.
A Generator Owner can get involved in the process by receiving a request for interconnection on their Facility and executing an Agreement to
evaluate the reliability impact of that request. The team has attempted to clarify to qualifying language in the applicability section with its
latest proposed changes. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s
rationale.
With respect to the VRF for R4, we agree that “low” might be more appropriate, but that change is outside the scope of this drafting team.
Your suggestion will be submitted in a Suggestion Form and added to NERC’s Issues Database to be addressed in a future project.
Project 2010-07 Consideration of Comments
13
Organization
Yes or No
Question 1 Comment
With respect to the moderate and high VSLs for R1, we agree that they are duplicative and believe this was a typo. Change made.
With respect to the proposed language change in the VSL for R4, while we agree that the VSL should be written in the negative rather than
the positive that change would be outside the scope of this drafting team. Your suggestion will be submitted in a Suggestion Form and added
to NERC’s Issues Database to be addressed in a future project.
PPL Supply Group
No
A Generator Owner subject to the proposed standard (i.e., with an executed Agreement to
evaluate the reliability impact of interconnecting another Facility to its existing generation
Facility) should only be responsible for evaluating the impact of such interconnection on its
facilities. Generation Owners should have no responsibility for evaluating impacts on
interconnected or adjacent Transmsision Owner systems. GOs do not have staff trained or tools
available to perform the studies necessary to evaluate reliability impacts of such
interconnections on Transmission Owner systems which can exend geographically far beyond
the POI. The SDT should clarify that Transmission Owners are solely responsible for evaluating
and addressing any impacts on their systems.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. The drafting team does not believe the
standard as written requires the Generator Owner to be responsible for any interconnection Facility past the point of interconnection with the
Transmission Owner’s Facility. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the
team’s rationale. No change made.
ACES Power Members
No
We support the concept of modifying FAC-001-1 to include Generation Owners that own
transmission lines that interconnect them to the BES for the purpose of eliminating the need to
register Generation Owners as Transmission Owners. However, there are serious issues with
the implementation of the FAC-001-1. The changes conflict with the tariff process of many
established markets as well as the FERC pro forma tariff. Requests to interconnect are
generally governed by tariffs. The request will be submitted to the transmission provider
established by the tariff. The transmission provider will then perform the necessary studies
such as system impact or feasibility studies to determine any necessary upgrades through its
long-term planning function. After the completion of these studies or in parallel with them, the
Transmission Owner (or Generation Owner that owns transmission) will perform the facility
connection study. This may or may not require an additional contract as it may be governed
completely under the tariff or may be covered under a blanket agreement in an organized
Project 2010-07 Consideration of Comments
14
Organization
Yes or No
Question 1 Comment
market. The language referring to the executed Agreement in the standard should be dropped
as it is confusing and may not cover many situations. Rather, the standard should apply to the
Generation Owner that owns Transmission and is not registered as Transmission Owner.
R2 should be modified such as the Generation Owner that owns Transmission is required to
create facility connection requirements upon request from the Planning Coordinator or
Transmission Planner. While the NERC Functional Model is not clear on the function that
performs the interconnection study, it likely will be either the Transmission Planner or the
Planning Coordinator. Interconnection studies are typically long-term planning studies. Thus, it
is the Transmission Planner or Planning Coordinator that will receive the interconnection
request and determine on whose equipment will be impacted.
R3 is problematic and contradicts the purpose of R2. R3 requires the Generation Owner that
owns Transmission to have Facility connection requirements at all times. It appears the
drafting team intended for R3 to simply define what must be included in the facility connection
requirements. To do this, we suggest the drafting team remove the Generation Owner that
owns Transmission from the requirement and copy the part 3.1 and its sub-parts to R2. The
following language should be struck from R2: “to ensure compliance with NERC Reliability
Standards and applicable Regional Entity, subregional, Power Pool, and individual Transmission
Owner planning criteria and Facility connection requirements”. These requirements already
exist elsewhere and inclusion here creates the potential for double jeopardy. R4 should be
struck. There is no need for the Generator Owner that owns transmission to maintain its facility
connection requirements. They should only be required to review and update them when they
get a request. Tariff processes will already require them to make the facility connection
requirements available to interconnection requesters.
Response: Thank you for your comment. The drafting team believes that the execution of an Agreement to evaluate the reliability impact of
interconnecting a third party Facility is the appropriate “activation” point for this standard for applicable Generator Owners. We have changed
the language in the requirement to accommodate situations where it was not the Generator Owner itself that executed the Agreement. Please
see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s rationale.
R3 has been modified to more clearly apply only to Generator Owners in accordance with R2. Per your suggestion about maintenance, the
drafting team has removed the maintenance obligation for Generator Owners. For more information on our rationale with respect to this,
please see the accompanying FAC-001-1 technical justification document.
Westar Energy
No
We suggest the VRF for R4 be changed from medium to low, as it is administrative in nature.
We recommend the high VSL for R1 read, “The Transmission Owner failed to do two of the
Project 2010-07 Consideration of Comments
15
Organization
Yes or No
Question 1 Comment
following.”
Response: Thank you for your comment. We agree that “low” might be more appropriate, but that change is outside the scope of this
drafting team. Similarly, any change to the VSLs for R1 is outside the scope of this drafting team as that requirement does not include any
reference to Generator Owners; we only made changes if the previous text appeared to have a typo. Your suggestions will be submitted in a
Suggestion Form and added to NERC’s Issues Database to be addressed in a future project.
Southern Company
No
A. Southern does not think that the revision to FAC-001-1 is necessary. A Generator Owner
(GO) cannot assess reliability impacts to the Bulk Electric System (BES) and determine
acceptability without support and involvement of the applicable owner and operator of the
Transmission System. A generator tie-line does not equate to a Transmission System. A GO
must already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties facilities to its own interconnection Facilities.
Stated another way, the GO does not need Facility Connection requirements to govern how
multiple units are tied to a collector bus so why are they needed for a third party to connect to
an existing tie-line? In either case it is the interconnected TO that has connection requirements
that must be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its interconnected
Transmission Provider. A GO should not need to develop “connection requirements” unless it is
in the business of owning and operating facilities independently of its interconnected
Transmission Provider.
We do not believe a reliability gap exists in FAC-001-1 because the requestor for
interconnecting another Facility to an existing generation Facility must coordinate with the
applicable TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable
facility connection and performance requirements. If and when there is an agreement in place
for a third party to connect to a generator tie-line then the tie-line would become part of the
integrated system and its purpose and the owner’s function would likely warrant registration as
a TO/TOP and FAC-001 would then apply. The following excerpt from the 2010-07 Background
Resource Document acknowledges that this may be necessary: “The drafting team also
acknowledges that, if another party interconnects to a Facility owned by a Generator Owner,
there may be the need to address MOD or TPL standards. However, the drafting team believes
that this, too, is best handled through specific evaluation, perhaps accompanied by changes to
the compliance registry. Entities that face this kind of scenario may also meet criteria applicable
to other registrations such as Transmission Service Provider or Transmission Planner.”
Project 2010-07 Consideration of Comments
16
Organization
Yes or No
Question 1 Comment
B. If the Project 2010-07 Drafting Team decides to continue revising FAC-001-1, there are
jurisdictional, interconnection policy and open access transmission tariff issues that will need to
be considered.
(1) Because of (a) jurisdiction under Section 215, (b) FERC’s interconnection policy, and (c)
the requirements of the pro forma open access transmission tariff (OATT), a GO should not be
required to comply with FAC-001-1 until that GO’s generating Facility reaches commercial
operation.
(a) Jurisdiction under FPA Section 215. First, it is not clear that NERC or FERC has
jurisdiction under FPA Section 215 to require generation facilities that have not actually
reached commercial operation to be subject to reliability standards. Section 215(a)(2) of
the FPA defines the “Electric Reliability Organization” as “the organization certified by the
Commission ... the purpose of which is to establish and enforce reliability standards for
the bulk-power system, subject to Commission review.” Further, (a)(3) provides that “The
term ‘reliability standard’ means a requirement, approved by the Commission under this
section, to provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide for
reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design of
planned additions or modifications. It is logical to interpret the phrase “design of new
facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted as
requiring that a generating facility that has not yet reached commercial operation should
be subject to reliability standards (including audit and penalties). Therefore, the GO with
the existing generation facilities should not be required to incorporate the proposed
generation facility into its Facility connection requirements before the proposed generation
facility is subject to NERC or FERC jurisdiction.
(b) FERC’s interconnection policy. In addition, the revised FAC-001 would appear to
place restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC was
very concerned about the ability of interconnection customers to interconnect their
generating facilities and gave them a fair amount of flexibility. However, this revised
Project 2010-07 Consideration of Comments
17
Organization
Yes or No
Question 1 Comment
FAC-001 would appear to restrict some of this flexibility.
(i) Order No. 2003 gives the interconnection customer the ability to terminate a
proposed interconnection on ninety days notice. Therefore, the interconnection
customer is not required to build the facility. However, this revised FAC-001
appears to assume that the interconnection customer does not have this flexibility.
What if the interconnection customer (the GO building a new generator on its site
or the third party building a new generation facility) decides to terminate the Large
Generator Interconnection Agreement (LGIA) or not proceed with the generation
facility? In such event, the GO may be required to revert to its previous Facility
connection requirements in order to accommodate the original configuration.
(ii) The LGIA permits modifications to the proposed interconnection. How would
this affect the Facility connection requirements? How long would the GO have to
revise its Facility connection requirements? In the event that there is a single
modification, or perhaps multiple modifications, how does the GO stay in
compliance with this standard?
(iii) FAC-001-1, R4 provides that each GO with Facility connection requirements
and each TO shall maintain Facility connection requirements and make
documentation of these requirements available to users of the Transmission
System upon request. However, Large Generator Interconnection Procedures
(LGIP), Section 3.4 requires the posting of certain interconnection information but
the identity of the interconnection customer is not to be disclosed (unless it is an
Affiliate). Requirement R4 would appear to potentially require disclosure of
information and (more importantly) of the interconnection customer's identity in
contravention of the requirements in Order No. 2003 and the LGIP.
(c) OATT requirements. The definition of “applicable Generator Owner” (Section 4.2.1)
and Requirement R2 provide that the GO will have an executed Agreement to evaluate
the impact of interconnecting a new facility to the GO’s existing generation facility. This
statement is ambiguous. This statement could be understood to mean that the GO of the
existing generation Facility will enter into an Agreement with the GO proposing to
interconnect and the existing GO will evaluate the impact of the proposed interconnection.
However, requests to interconnect new generation are processed under an OATT. In that
case, it would be the Transmission Provider (not the existing GO) that would evaluate the
impact of interconnecting the new facility. Thus, the language in FAC-001-1 would need
Project 2010-07 Consideration of Comments
18
Organization
Yes or No
Question 1 Comment
to be revised to clarify that the owner of the new facility will need to interconnect under
the OATT of an appropriate Transmission Provider (i.e., the Transmission Provider to
which the existing GO is interconnected, not with the existing GO). Therefore, the owner
of the new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be developing
a merchant transmission line. In that case, the existing GO would need to evaluate
whether it needs have its own OATT and OASIS. In that case, the new generator owner
would be interconnecting to the existing GO. However, the existing GO’s line would not
be a generator tie-line. This issue is not clear from the draft standard.
(2) The following are suggested changes to FAC-001-1.
(a) We recommend the Purpose statement be revised to state, “To avoid adverse impacts
on BES reliability...”
(b) The numbering for “Applicable Generator Owner” should be 4.2.1 instead of 2.4.1.
(c) It is not clear who may request to interconnect to the Generator Owners’ facility. The
Background Resource document states that “[b]ecause Generator Owners may be
requested to allow interconnection to their Facilities” - this would imply that a third party
may request interconnection to the Generator Owner’s Facilities. However, draft FAC001-1 discusses “interconnecting another Facility to its existing generation Facility.” This
issue needs to be clarified. Is it simply when a Generator Owner proposes to add a new
facility to its existing facility or does it also include a third party request to interconnect to
the Generator Owner facilities?
(d) R4 should be revised to delete the requirement to maintain the Facility connection
requirements because this is redundant to language in R1 (and R2, which we believe is
not needed). In addition, R4 should be revised to state, “...on requests within five (5)
business days” since the time requirement is essential for measurement of noncompliance as indicated by the VSLs.
(e) The Severe VSL for R3 should be revised to delete the second portion which states,
“The responsible entity does not have Facility connection requirements.” This noncompliance would be covered by the first portion of the two-part OR requirement (...four
or more...). It is also covered by the Severe VSL of R1.
(3) Effect of the proposed revisions to FAC-001-1 on FAC-002-1.
Project 2010-07 Consideration of Comments
19
Organization
Yes or No
Question 1 Comment
(a) As drafted, there are scenarios under which a new GO may attempt to interconnect to
an existing GO even though, as explained above, the interconnection should actually be
done to the appropriate Transmission Provider. If the appropriate Transmission Provider
is not included in the evaluation of the interconnection various types of harm may occur.
In such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002.
(b) FAC-001 and FAC-002 should be revised to be clear that the existing GO and any new
GOs must coordinate any interconnection with the appropriate Transmission Provider, TP
and PA.
Response: Thank you for your comment. The drafting team has considered the jurisdictional, interconnection policy and open access
transmission issues that you raise. But in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. You are correct that a jurisdictional,
interconnection policy, and open access transmission tariff issues maybe have an impact, but it would be inappropriate for any market- or
tariff-related language to be included in a NERC Reliability Standard. The goal of the drafting team was simply to clarify a Generator Owner’s
obligations, under NERC’s Reliability Standards, for handling an interconnection request and the related interconnection requirements. Please
see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s rationale.
With respect to your suggested changes in section 2:
a. Any change to the purpose statement would be outside the scope of this team. Please submit a Suggestion Form to NERC if you continue
to feel that this change is necessary.
b. That formatting change has been made.
c. The drafting team has worked to clarify who may request to interconnect to the Generator Owner’s Facility.
d. The maintenance requirements in R2 and R4 are no longer applicable to Generator Owners. For more information on our rationale on this
issue, please see the accompanying FAC-001-1 technical justification document.
e. The drafting team agrees that the second portion of the Severe VSL for R3 is redundant. While other changes to VSLs and VRFs have been
outside the scope of the team, because the SDT has made changes to R3, we feel comfortable making this change.
For a more detailed justification of our changes to FAC-001 with respect to your comments in the third section, please see the FAC-001
justification document that is posted with these standard changes.
American Electric Power
No
There are substantial reliability issues, as well as additional regulatory, tariff, coordination, and
generator and interconnection facility issues, which need to be dealt with before AEP could
agree to such requirements. It is not clear that a generator can receive a request for
Project 2010-07 Consideration of Comments
20
Organization
Yes or No
Question 1 Comment
interconnection. We recommend adding qualifier text which states the standard only applies
*if* an entity plans to allow such a requested interconnection. This would allow an entity to
document that they do not plan to allow such interconnections.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. No change made.
APS
No
Do not agree with adding GO to FAC-001-1
Response: Thank you for your comment. The vast majority of stakeholder commenters and the drafting team continue to support the
addition of the Generator Owner to the applicability of FAC-001-1. No change made.
Exelon
No
Exelon does not agree that this standard should be broadly applied to a GO. GOs who do not
own a switchyard and whose point of interconnection is a disconnect switch associated with the
generator leads prior to the switchyard should be excluded from this standard. If a group of
GOs share a generator tie line, then the associated Interconnect Agreement that each of the GO
has with the applicable TO and/or TOP should address how these shared connections will effect
the system. GOs may not have the resources or expertise to conduct the required interconnect
studies to meet this standard
Response: Thank you for your comment. The standard does not automatically apply to all Generator Owners; rather, it applies only to those
Generator Owners with an executed Agreement to evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the Transmission System. The drafting team believes that it has built the appropriate
amount of time into the standard to allow an applicable Generator Owner to evaluate the impact of an Interconnect Agreement and obtain or
contract for the necessary resources and expertise. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed
explanation of the team’s rationale. No change made.
Manitoba Hydro
No
The Applicable Entities now include a Generator Owner that meets the following condition:
‘Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting another Facility to its existing generation Facility.’ A Generator Owner should
not have such power. In many instances Generator Owners do not have the models or
expertise to perform interconnection studies to determine if there is an impact on the
Transmission Network. All interconnection requests should be implemented by the
Transmission Owner (TO) regardless if the interconnection point is within a Generation Owner
Project 2010-07 Consideration of Comments
21
Organization
Yes or No
Question 1 Comment
facility or End-User facility. The TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If a mechanism is created to
allow interconnection to a BES line owned by Generator Owner, then it is essential for this
Generator Owner providing this interconnection service to be a TO to ensure all reliability
standards, including the protection standards, are met so the reliability of the BES is
maintained. The drafting team should demonstrate where this situation is occurring.If the
redline changes are implemented, could Generator Owner #1 permit Generator Owner #2 to
interconnect one of their generators within Generator Owner #1’s Facility? Would Generator
Owner #2 then need to have an executed Agreement to permit further generator
interconnection? From a Transmission Owner viewpoint, it is tough enough to coordinate
generator connection queues among adjacent TOs. Having to coordinate with Generator
Owners as well would greatly increase the complexity of coordination.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. No change made.
American Transmission
Company
No
R1 wording in this draft only requires having published Facility connection requirements, but
speaks nothing of specific required content of this published document. (R1) VSLs specifically
reference R1. If VSLs continue to include assessment of how many R3 (R2 in present standard)
requirements are met, a TO potentially has a redundant obligation under two separate
requirements. R1 and R3 do not read in a manner consistent with (R1) VSLs. Since R2 only
applies to Generator Owners, the (R2) VSL should use “Generator Owner” in place of
“responsible entity.”
Response: Thank you for your comment. The drafting team has removed the second portion of the Severe VSL for R3 to eliminate potential
redundancy with the VSLs for R1 and R2. The VSL for R2 now refers to “Generator Owner” rather than “responsible entity.”
Xcel Energy
Yes
We believe it would be helpful to put explanatory wording in that if an entity is already
registered as a Transmission Owner and Generator Owner, the Generator Owner portion of that
entity would not have to have a separate set of interconnection requirements.
Response: Thank you for your comment. The Facility in question in the standard would either be owned by the Generator Owner or the
Transmission Owner. The owner must meet the requirement. The SDT does not determine how an entity complies, though we could expect
that if an entity is already an Transmission Owner, it could easily simply apply its already existing set of interconnection requirements to any
Project 2010-07 Consideration of Comments
22
Organization
Yes or No
Question 1 Comment
new Facilities that are applicable under this standard.
Ingleside Cogeneration LP
Yes
However, there may need to be a variance for ERCOT because the Power Generating
Companies in ERCOT are not allowed to own transmission assets.
Response: Thank you for your comment. If companies in ERCOT are not allowed to own transmission assets, the drafting team assumes that
they would also never be in a position to have an Agreement to execute the reliability impact of an interconnection request. No change made.
Georgia Transmission
Corporation
Yes
We commend the drafting team for their efforts to address gaps in Facility Connection
Requirements. We believe that the requirements under R3 should be limited to Generator
owned equipment to avoid duplication of efforts. A Generator Owner receiving an
interconnection request is required to submit an interconnection request to the Transmission
Owner which in turn would study the impact of such a request on the Transmission System.
Therefore there is no gap as far as the Integrated Transmission System that the third party is
interconnecting to through the Generator Owner. However, Generator Owners are responsible
for verifying that their equipment is capable of accommodating the interconnection request.
Response: Thank you for your comment. The SDT does not believe that R3 is duplicative; there is no reason to assume that the
Transmission Owner or the applicable Generator Owner would be addressing anything but the equipment that it owns. No change made.
BGE
Yes
This change closes the gap in areas not already covered under FAC-003-1 in a continuous
improvement effort to ensure vegetation-related transmission reliability for applicable lines.
Response: Thank you for your comment.
FirstEnergy Corp
Yes
FirstEnergy (FE) appreciates the drafting team's careful consideration of the comments made
by FE during the most recent informal comment peroid. The changes made to FAC-001
alleviate FE's prior concern related to a Generator Owner needing to maintain and publish a
Facility Connection requirements document regarding facilities which are not yet subject to
Open Access provisions. FE supports the team's changes to FAC-001-1 and the concept that a
connection requirement document would be required upon the initial or 1st time a Generator
Owner executes an Agreement to perform the reliability assessment required in FAC-002-1.
Response: Thank you for your comment.
Project 2010-07 Consideration of Comments
23
Organization
Sempra Generation
Yes or No
Yes
Question 1 Comment
Sempra Generation supports the proposal for the compliance obligations under R2 associated
with an interconnection request not to be triggered until an interconnection study agreement
has been executed.
Response: Thank you for your comment.
Arizona Public Service
Company
Yes
These comments supersede the previous comments submitted by Arizona Public Service
Company on July 7, 2011.
Response: Thank you for your comment.
SERC OC Standards Review
Group
Yes
Consider a better definition of what constitutes an “applicable” generator owner or point to the
document that explains the definition.
Response: Thank you for your comment. The drafting team attempted to clarify the description of an “applicable” Generator Owner in the
latest standards changes.
Imperial Irrigation District
(IID)
Yes
PacifiCorp
Yes
Ameren
Yes
Luminant Power
Yes
Constellation Power
Generation
Yes
SERC Planning Standards
Subcommittee
Yes
Duke Energy
Yes
Project 2010-07 Consideration of Comments
24
Organization
Yes or No
Tri-State Generation and
Transmission, Inc.
Yes
Electric Market Policy
Yes
Bonneville Power
Administration
Yes
Indeck Energy Services
Yes
CHPD
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Tacoma Power
Yes
Notheast Power Coordinating
Council
Yes
TransAlta Centralia
Generation LLC
Yes
EPSA
Question 1 Comment
Background: The Electric Power Supply Association (EPSA) endorsed the initial
recommendations of the Ad Hoc Group for Generator Requirements at the Transmission
Interface, offered informal comments on the March 2011 White Paper Proposal for Project
2010-07 and now appreciates this opportunity to provide comments on the questions posted
June 17, 2011. Since NERC’s creation of the “GOTO Team” in February of 2009, EPSA has
supported the efforts of Ad-Hoc Group and now the Project 2010-07 Standards Drafting Team
(SDT). While EPSA members’ compliance registration includes several functional entity types,
the bulk of competitive suppliers’ registrations are as Generator Owners (GOs) and Generator
Project 2010-07 Consideration of Comments
25
Organization
Yes or No
Question 1 Comment
Operators (GOPs).
EPSA applauds the SDT’s decision to recommend the use the “intent of obligation” as the
reason for application of FAC-001 rather than the receipt of request for interconnection and
thereby supports the revisions to FAC-001-1. The proposed modification to FAC-001 (a new R2)
would require a GO to develop “Facility connection requirements” within “45 days of executing
an Agreement to evaluate the reliability impact of interconnecting another Facility to its existing
generation Facility...” The use of the agreement execution is a more reasonable triggering
mechanism for FAC-001 application and compliance. The SDT’s recommendation intentionally
excluded specific reference to the form of agreement to avoid commingling commercial and
reliability aspects in reliability standards.
However, the existing language may still may mix commercial and reliability issues. The
accompanying project Background Resource Document (p.2) makes it clear that the
interconnection to an existing generator facility is contemplated to be the “existing
interconnecting Facility that is owned by a generator” - that is, the generator’s lead. The
generator’s leads are considered part of the “existing generator Facility,” however, the
generator, step-up transformer and other equipment that is within the generator switchyard
can also be considered part of the Facility. FERC requires all transmission facilities to be
available for “open access.” A generator lead would become open access if another customer
interconnected to it. Therefore FAC-001-1 could be made clearer by modifying the language
regarding the 45-day trigger as follows: within “45 days of executing an Agreement to evaluate
the reliability impact of interconnecting another Facility to its the Generator Owner’s existing
generation interconnecting transmission Facilities...” This modification would make it clear that
the requirement does not apply to an entity that wants to, for example, connect a new
generator within the fenced-in site of the existing generator, but instead only applies to request
to interconnect to the generator lead.
Response: Thank you for your comment. The drafting team has attempted to make this clarification regarding the “activation” of the
applicability of this standard with respect to Generator Owners.
Utility Services, Inc.
LG&E and KU Energy
Project 2010-07 Consideration of Comments
26
Organization
Yes or No
Question 1 Comment
Wisconsin Electric
Project 2010-07 Consideration of Comments
27
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan
for FAC-001-1?
Summary Consideration: Most commenters supported the one year compliance timeframe for Generator Owners
as proposed in the Implementation Plan for FAC-001-1. A few suggested a longer timeframe, but the drafting team
believes it has built in the appropriate amount of time by giving a year in the implementation plan and then waiting
to “activate” the standard until a Generator Owner has an executed Agreement to evaluate the reliability impact of
the interconnection request.
Organization
Manitoba Hydro
Yes or
No
No
Question 2 Comment
See question #1 comments. We do not support changing the applicability of FAC001-1 to include Generator Owners ‘with an executed Agreement’ or Generator
Owners that own BES transmission.
Response: Thank you for your comment. Please see our response to your Question 1 comments above.
Ingleside Cogeneration LP
No
As drafted, the document still refers to generation interconnection lines as
transmission lines in critical places. We understand that the SDT has taken
significant steps to minimize this in both FAC-001 and FAC-003 and has had
discussions with NERC about not registering GOs as TOs; however, this lack of
distinction between high voltage generation interconnection lines and actual
transmission lines still presents a difficult situation for Generations Owners and a
source of contention with Reliability Entities. This could be resolved somewhat by
using the non-defined term “generation interconnection lines” in place of
“transmission lines” in, for example, section 4.3.1. Since the term “transmission line”
is also undefined, this would seem to be a reasonable approach.
Response: Thank you for your comment. We have provided a disclaimer about the use of the term “transmission lines” in FAC003, and have avoided use of the term elsewhere.
APS
No
Leave the GO out of the standard.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting
Project 2010-07 Consideration of Comments
28
Organization
Yes or
No
Question 2 Comment
team thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability Standards by including
applicable Generator Owners in FAC-001-1.
SERC OC Standards Review
Group
No
We feel that an 18 month implementation plan would be more conducive for
generators to meet these new requirements
Response: Thank you for your comment. The drafting team believes it has built in an adequate amount of time by giving a year in
the implementation plan and then waiting to “activate” the standard until a Generator Owner has an executed Agreement to
evaluate the reliability impact of the interconnection request.
PPL Supply Group
No
It may take longer since very few (if any) GOs are prepared to perform this type of
work.
Response: Thank you for your comment. The drafting team believes it has built in the appropriate amount of time by giving a
year in the implementation plan and then waiting to “activate” the standard until a Generator Owner has an executed Agreement
to evaluate the reliability impact of the interconnection request.
BGE
Yes
This requirement is consistent with the initial time frame when FAC-003-1 was first
implemented.
Response: Thank you for your comment.
Southern Company
Yes
However, we do not believe it is necessary to require a GO to have Facility connection
requirements as we discuss in our response to Question 1.
Response: Thank you for your comment. Please see our response to your Question 1 comments above.
FirstEnergy Corp
Yes
The one year lead time is sufficient lead-time to notice the GOs of new expectations
required under FAC-001-1.
Response: Thank you for your comment.
Notheast Power Coordinating
Yes
Project 2010-07 Consideration of Comments
29
Organization
Yes or
No
Question 2 Comment
Council
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
SPP Reliability Standards
Development Team
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
EPSA
Yes
PacifiCorp
Yes
Arizona Public Service
Company
Yes
Project 2010-07 Consideration of Comments
30
Organization
Yes or
No
Westar Energy
Yes
Luminant Power
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Tacoma Power
Yes
Duke Energy
Yes
Constellation Power
Generation
Yes
Ameren
Yes
Indeck Energy Services
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
Project 2010-07 Consideration of Comments
Question 2 Comment
31
Organization
TransAlta Centralia
Generation LLC
Yes or
No
Question 2 Comment
Yes
Georgia Transmission
Corporation
Wisconsin Electric
Utility Services, Inc.
Exelom
LG&E and KU Energy
American Transmission
Company
Project 2010-07 Consideration of Comments
32
3. Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will
be made as the Project 2010-07 drafting team learns more about the status of Project 2007-07—Vegetation
Management, do you support the proposed redline changes to FAC-003-X and FAC-003-3?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-003-X and FAC-003-3, and the drafting team made
additional changes, based on commenter feedback, where the team believes those changes add clarity.
Many commenters focused on the half-mile qualifier in FAC-003-X and FAC-003-3. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the
switchyard, generating station, or generating substation to be confusing. The drafting team attempted to address all
of these concerns with its latest proposed standard changes. The qualifier now reads: “…that extends greater than
one mile beyond the fenced area of the generating station switchyard…” The drafting team believes that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of the
generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an
auditor. Finally, the team maintains that it is appropriate to include this qualifier for Generator Owners because there
is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are not
necessary to ensure reliability of these lines.
One commenter caught typos in the Effective Dates sections of the standards, and those typos have been corrected.
Single commenters brought up minority issues, but the SDT found no justification for these issues. We address those
minority issues in our responses to the specific comments below.
Organization
American Transmission
Company
Yes or
No
No
Question 3 Comment
ATC does not support the changes for FAC-003-X, however, ATC does support
FAC-003-3.
FAC-003-X Concerns. The VRF and VSL tables do not correlate to the original
FAC-003-1 levels of non-compliance section D.2. ATC believes that section D.2
should be rewritten to align with the already approved FAC-003-1.
FAC-003-X Corrections- Applicability Section 4.3.1, sentence 3 - Transmission
should not be capitalized.
Project 2010-07 Consideration of Comments
33
Organization
Yes or
No
Question 3 Comment
FAC-003-3 - No Concerns
Response: Thank you for your comment. The VSLs and VRFs in FAC-003-X were taken from already approved NERC
projects to update all early versions of standards with VSLs and VRFs instead of levels of non-compliance. Any additional
changes to those VSLs and VRFs would be beyond the scope of this drafting team. No change made.
Applicability Section 4.3.1 no longer includes a capitalized version of Transmission (just a reference to the “Transmission
Owner’s Facility”).
Public Service Enterprise
Group
No
FAC-003-X and FAC-003-3 both have similar “one half mile” language, the
starting point for the one half mile is vague. In FAC-003-X, the language in
4.3.1 reads “Generator Owner that owns an overhead Facility that extends
greater than one half mile beyond the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection
with the Transmission system and ...” While we support the one half mile
language, there are three possible staring points for the measurement of the
one half mile: beyond the fenced area of (i) the switchyard, (ii) the generating
station, or (iii) the generation substation. While a GO’s fencing policy may
differ between generation stations, the requirement to implement vegetation
management should be clear. For clarity, while we believe that the language
should retain flexibility with regards to “fencing” by the Generator Owner, it
should be clear that the Generation Owner determines the starting point.
Second, a Generator Owner’s overhead Facility that is within the fence should
explicitly not be applicable to the standard. Finally, we believe the language
that refers to the “interconnection with the Transmission system” should be
changed to “interconnection with a Transmission Owner’s Facility. The reason
is that the term “Transmission” which is defined in the NERC Glossary could be
construed to include all of a Generator Owner’s interconnection leads. (The
definition is excerpted from the Glossary in our response to question 7)
Therefore, we suggest that the language in 4.3.1 be modified as follows to
make all of these points clear: A Generator Owner that owns an overhead
Facility that extends greater than one half mile beyond the fenced area of
either the generator switchyard, generating station or generating substation
(as specified by the Generation Owner) up to the point of interconnection with
Project 2010-07 Consideration of Comments
34
Organization
Yes or
No
Question 3 Comment
a Transmission Owner’s Facility and is operated 200 kV and above and any
lower voltage lines designated by the RE as critical to the reliability of the
electric system within the region is applicable to this standard.”
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team agrees that “interconnection with a Transmission Owner’s Facility” adds clarity. That change has been
made.
SPP Reliability Standards
Development Team
No
In both FAC-003-3 and FAC-003-X it lists “greater than one half mile cutoff”.
We would recommend that the distance cutoff be removed. We feel that
overhead Facilities shouldn’t be treated any differently than any other. Also we
would like to see these two sections in both standard proposals reflect similar
language for 4.3.1.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Project 2010-07 Consideration of Comments
35
Organization
PPL Supply Group
Yes or
No
No
Question 3 Comment
Version 3 (based on V2): Third Effective date appears to contain a
typographical error.
Version X (based on V1): Same as Version 3 comments.
Please consider streamlining the section Background (Version 3).
Response: Thank you for your comment. The typographical errors were corrected in both versions of the standard.
Streamlining the Background section in Version 3 is not within the scope of this drafting team. No change made.
Westar Energy
No
The language in the applicability section 4.3.1 in both FAC-003-3 and FAC-003X states “extends greater than one half mile beyond...” We propose that the
SDT consider removing the distance exclusion to be consistent with language
for Transmission Owner Facilities and treat all overhead facilities the same.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Southern Company
No
(1) We question whether R1 of FAC-003-3 would ever apply to a GO who owns
transmission interconnection equipment. Can the SDT provide an example or
two in the Guideline and Technical Basis section of the standard?
(2) We recommend rearranging the language in R5 of FAC-003-3 to state, “The
applicable Transmission Owner or applicable Generator Owner shall take
corrective action to ensure continued vegetation management to prevent
encroachments when...” This places the “shall” at the beginning of the
Project 2010-07 Consideration of Comments
36
Organization
Yes or
No
Question 3 Comment
requirement which is clearer and consistent with the structure of the other
requirements.
(3) We question why there are no VSLs assigned to R4. Should there be?
What are the consequences if a Regional Entity does not comply?
(4) There does not appear to be any coordination with the Vegetation
Management Standard Drafting Team (VMSDT) concerning proposed
modifications to the standard. The VMSDT should be consulted.
Response: Thank you for your comment.
(1) The SDT is not currently aware of specific examples where R1 would apply, but we do not see any reason to remove that
reference, as it could apply in the future. If we removed it now, we’d create a reliability gap, but if we leave it in, no
Generator Owner has to take action unless it has an IROL or WECC transfer path.
(2) This change is beyond the scope of our drafting team. It is an issue that should have been addressed under Project
2007-07. We will submit the issue in a Suggestion Form to be added to NERC’s Issues Database.
(3) Because the Regional Entity is not a Functional Entity, it cannot be assigned penalties under NERC’s Reliability Standards.
(4) The Project 2007-07 Vegetation Management drafting team’s latest draft standard has already passed ballot, so
coordination with that team was no longer a possibility.
APS
No
Leave the GO out of both Standards proposed.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making
both FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the
generator interconnection Facility are covered under NERC Reliability Standards. No change made.
Indeck Energy Services
No
4.3.1.3 is a regional variation. The ROP doesn't permit members of one region
to vote on regional requirements for another region. A separate regional
standard will be required.
Response: Thank you for your comment. It is our understanding that any stakeholder can vote on regional requirements as
long as they’re in the body of the standard. This does not require a separate regional standard.
Project 2010-07 Consideration of Comments
37
Organization
Ingleside Cogeneration LP
Yes or
No
Question 3 Comment
No
Ingleside Cogeneration LP believes there should be a relaxation in the
vegetation management requirements for those interconnections which only
serve as a radial link to the BES. Although we fully understand the importance
of keeping vegetation away from high voltage lines, the one year period is
much too frequent in our generator locations. The added documentation and
other expenses simply do not justify the non-existent gain in reliability when
vegetation in a locale (e.g.; desert) never reaches five feet above the ground.
Consider limiting this exception to units below a certain MVA rating that are not
critical to the BES - perhaps coupled with evidence that vegetative intrusions
are highly unlikely.
Response: Thank you for your comment. We have attempted to set up a reasonable qualifier/balance with the new one mile
designation and “stake in the ground” at the fenced line of the switchyard. Because of a perceived reliability gap at the
interconnection between Generator Owner Facilities and Transmission Owner Facilities, we are doing our best to apply the
same Transmission Owner vegetation management requirements to the Generator Owner. This issue you raise (with respect
to the vegetation in certain locales) could possibly be applied to other entities besides the Generator Owner if it was
technically justified, so the drafting team encourages you to submit a SAR suggesting this.
Notheast Power Coordinating
Council
No
See comments in the following questions.
EPSA
Yes
EPSA generally supports the SDT’s proposed redline changes to FAC-003-X and
FAC-003-3 and SDT’s diligence in monitoring Project 2007-07. There is one
distinction however that EPSA would like to bring to the SDT’s attention that
could increase clarity. FAC-003-X and FAC-003-3 both have similar “one half
mile” language, but the starting point for the one half mile can occur one of
three ways.
In FAC-003-X, the language in 4.3.1 reads “Generator Owner that owns an
overhead Facility that extends greater than one half mile beyond the fenced
area of the switchyard, generating station or generating substation up to the
point of interconnection with the Transmission system and ...” Therefore,
there are three possible staring points for the measurement of the one half
mile: beyond the fenced area of (i) the switchyard, (ii) the generating station,
Project 2010-07 Consideration of Comments
38
Organization
Yes or
No
Question 3 Comment
or (iii) the generation substation. While it would appear implicit that GO’s
would determine which of the three was used to make the determination that
the GO determines the starting point.
Another point for consideration is that a Generator Owner’s overhead Facility
that is within the fence should explicitly not be applicable to the standard.
EPSA believes the language that refers to the “interconnection with the
Transmission system” should be changed to “interconnection with a
Transmission Owner’s Facility. The reason is that the term “Transmission”
which is defined in the NERC Glossary could be construed to include all of a
Generator Owner’s interconnection leads. Therefore, we suggest that the
language in 4.3.1 be modified as follows to make all of these points clear:A
Generator Owner that owns an overhead Facility that extends greater than one
half mile beyond the fenced area of either the generator switchyard, generating
station or generating substation (as specified by the Generation Owner) up to
the point of interconnection with the Transmission Owner’s Facility and is
operated 200 kV and above and any lower voltage lines designated by the RE
as critical to the reliability of the electric system within the region is applicable
to this standard.”
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team agrees that “interconnection with a Transmission Owner’s Facility” adds clarity. That change has been
made.
Project 2010-07 Consideration of Comments
39
Organization
BGE
Yes or
No
Yes
Question 3 Comment
As noted in Question-1 above.
Response: Thank you for your comment. See our response to Question 1.
SERC OC Standards Review
Group
Yes
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Arizona Public Service
Company
Yes
Luminant Power
Yes
Project 2010-07 Consideration of Comments
40
Organization
Yes or
No
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Georgia Transmission
Corporation
Yes
Exelom
Yes
Duke Energy
Yes
Constellation Power
Generation
Yes
Ameren
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Yes
Project 2010-07 Consideration of Comments
Question 3 Comment
41
Organization
Yes or
No
Question 3 Comment
Generation LLC
LG&E and KU Energy
Manitoba Hydro
Tacoma Power
Wisconsin Electric
Utility Services, Inc.
Project 2010-07 Consideration of Comments
42
4. The drafting team has added Generator Owners to the Applicability sections of FAC-003-X and FAC-003-3 with the
qualifier that the included lines “extend greater than one half mile beyond the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection with the Transmission system.” The
team received many comments about the need to define a distance rather than other measures for exclusion, and
decided on the one half mile as a reasonable distance. Do you agree with this half-mile qualifier?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-003-X and FAC-003-3, and the drafting team has made
additional changes, based on commenter feedback, where they think those changes add clarity.
The drafting team received many comments about the half-mile qualifier in FAC-003-X and FAC-003-3. Some
commenters found the half-mile length too short, others found it too long, and still others found the choice among
the starting points of the switchyard, generating station, or generating substation to be confusing. The drafting team
attempted to address all of these concerns with its latest proposed standard changes. The qualifier now reads:
“…that extends greater than one mile beyond the fenced area of the generating station switchyard…” The SDT
believes that the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point
(at the fenced area of the generation station switchyard) eliminates confusion and any discretion on the part of a
Generator Owner or an auditor. Finally, the team maintains that it is appropriate to include this qualifier for
Generator Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps
in this standard are not necessary to ensure reliability of these lines.
One commenter suggesting including the equivalent kilometer length in the qualifying language in the standard, and
we have made that change.
Organization
Northeast Power
Coordinating Council
Yes or
No
No
Question 4 Comment
The qualifier should be similar to that specified in Part 4.2.4 of FAC-003-3:
“This standard applies to overhead transmission lines identified above (4.2.1
through 4.2.3) located outside the fenced area of the switchyard, station or
substation and any portion of the span of the transmission line that is crossing
the substation fence. “ Vegetation needing attention can exist within a half
mile of a switchyard. Vegetation does not discriminate between Generation
and Transmission Owners.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC-003-
Project 2010-07 Consideration of Comments
43
Organization
Yes or
No
Question 4 Comment
X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others found the
choice among the starting points of the switchyard, generating station, or generating substation to be confusing. The drafting
team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now reads: “…that
extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of the generation
station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor. Finally, we
maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from vegetation
within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these lines.
SPP Reliability Standards
Development Team
No
See comment above. We feel like there is no need for using a distance
exclusion.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
PPL Supply Group
No
Version 3 (based on V2):Comments: Although the “one half mile” is much
clearer than “two spans”, what is the rationale for choosing ½ mile as
opposed to another length such as 1 or 2 miles? Version X (based on V1):
Same as Version 3 comments
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
Project 2010-07 Consideration of Comments
44
Organization
Yes or
No
Question 4 Comment
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Bonneville Power
Administration
No
BPA believes that there needs to be a clear demarcation where Transmission
Owner and Generator Owner responsibilities begin and end.
Response: Thank you for your comment. The drafting team is operating under the assumption the Generator Owner’s
responsibilities to its interconnection Facility up to the point of interconnection with the Transmission Owner’s Facility, and
we have attempted to make that clear in our draft standards. We are considering changes to the definitions of Generator
Owner and Generator Operator, or creation of new terms to provide additional clarity in the next steps of our project plan,
pending Standards Committee approval.
Arizona Public Service
Company
No
The generator should be responsible no matter the length from fence area to
the point of interconnection.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Southern Company
No
Project 2010-07 Consideration of Comments
We agree with a one-half mile line as being “within the Generator Owner’s line
of sight and could be visually monitored for vegetation conditions on a routine
basis.” However, we suggest that some generation interconnection Facilities
greater than ½ mile in length could also fall within the GO’s line of sight or be
constructed such that they should be considered for exemption. Thus, the
Task Force should consider including exclusions for longer generator tie lines if
45
Organization
Yes or
No
Question 4 Comment
the GO can provide sufficient justification. Examples of justifications could
include (1) a clear line of sight, (2) pavement, gravel, or other non-vegetation
covered path, or (3) routine monitoring is performed from a roadway parallel to
the line, etc. Do not obviate any other transmission requirements such as the
following (which are incorporate into the draft standard):i. Operated at 200kV
or higher; orii. Operated below 200kV and included in IROL; or iii. Operated
below 200kV and inclusion in a Major WECC Transfer Path
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The issue you raise with respect to justification for further exclusions could possibly be applied to other entities besides the
Generator Owner (assuming it was technically justified), so the drafting team encourages you to submit a SAR suggesting
this.
APS
No
Leave GOs out of the standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making
both FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the
generator interconnection Facility are covered under NERC Reliability Standards. No change made.
Ingleside Cogeneration LP
No
The SDT needs to clarify that the one-half mile distance is measured from the
property line of the Generation Owner, i.e., an interconnection line that is in a
ROW.In addition, the half mile qualifier makes sense only for those
interconnections into critical generation facilities. See our response under
Question #3.
Project 2010-07 Consideration of Comments
46
Organization
Yes or
No
Question 4 Comment
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Wisconsin Electric
No
In addition to the "greater than one-half mile" criteria, we maintain there
should also be an exclusion for lines up to one mile in length which are entirely
on the Generator Owner's property.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Ameren
No
(1)We do not agree there should be a ½ mile exemption. On what legitimate
basis could we say the first ½ mile is not important? (2) There may be
different usage of the term "point of interconnection" in the industry. We
suggest the SDT to consider proposing a formal definition of this term.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
Project 2010-07 Consideration of Comments
47
Organization
Yes or
No
Question 4 Comment
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team is considering proposing a formal definition of the term “point of interconnection,” or other definitional
changes to make the use of that term clearer.
Westar Energy
No
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Although the NSRF agrees with the 1/2 mile criteria (see question 1); we
believe the drafting team will have to develop additional justification for this
criteria given FERC's recent orders, RC11-1 and RC11-2 (see question 6 for full
FERC Order details). In these orders FERC "implies" that if the GO/GOP is
responsible for a breaker operated at 100kV or higher the entity should be
required to register as a TOP/TO. Therefore it appears FERC would not be
inclined to provide any leeway based on distance from the substation. The SDT
should note that the FERC Order points to this Project to "address matters
involving reliability obligations at the interface of the transmission grid", which
is foot note 58.
Response: Thank you for your comment.
SERC Planning Standards
Subcommittee
Yes
However, we are concerned that there may be a reliability gap for locations
where there is not a half-mile line-of-sight from the generation switchyard.
Response: Thank you for your comment. The SDT believes these cases are limited enough that an exclusion within the
standard is not necessary. If you believe it is, we encourage you submit to a Suggestion Form.
EPSA
Yes
Project 2010-07 Consideration of Comments
EPSA appreciates the SDT proposing to use the approach that provides a
48
Organization
Yes or
No
Question 4 Comment
specific distance for determining which GO Facility lead lines that FAC-003
should apply to. EPSA agrees that the half-mile qualifier provides a discrete
parameter that will limit ambiguity in the Standard.
Response: Thank you for your comment.
LG&E and KU Energy
Yes
Although the “one half mile” is much clearer than “two spans”, what is the
rationale for choosing ½ mile as opposed to another length such as 1 or 2
miles?
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Independent Electricity
System Operator
Yes
We generally agree with the proposed distance. However, we suggest that in
Applicability Section 4.3.1 of the two draft standards, an equivalent kilometer
value be inserted after the “one half mile”.
Response: Thank you for your comment. We have added the equivalent kilometer value.
SERC OC Standards Review
Group
Yes
While we agree, we believe that a better explanation of “the fenced area of the
switchyard, generating station or generating substation up to the point of
interconnection with the Transmission system” should be included. One
suggestion is to distinguish between a plant perimeter fence and an internal
switchyard fence.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FACProject 2010-07 Consideration of Comments
49
Organization
Yes or
No
Question 4 Comment
003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
BGE
Yes
1/2 mile is a distance that can generally be viewed from one location, e.g. the
switchyard, and can be construed to present minimal risk since switchyards
have a reasonably frequent personnel presence that could be expected to
notice vegetation issues in the <1/2 mile area.
Response: Thank you for your comment.
Electric Market Policy
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
ACES Power Members
Yes
PacifiCorp
Yes
Luminant Power
Yes
American Electric Power
Yes
Project 2010-07 Consideration of Comments
50
Organization
Yes or
No
Xcel Energy
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
BP Wind Energy North
America Inc.
Yes
Georgia Transmission
Corporation
Yes
Exelom
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Generation LLC
Yes
Duke Energy
Yes
Indeck Energy Services
Yes
Constellation Power
Generation
Yes
CHPD
Yes
Question 4 Comment
Utility Services, Inc.
Manitoba Hydro
Project 2010-07 Consideration of Comments
51
Organization
Yes or
No
Question 4 Comment
Tacoma Power
American Transmission
Company
Project 2010-07 Consideration of Comments
52
5. Do you support the two year compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X and FAC-003-3?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The vast majority of
commenters supported the two-year compliance timeframe for Generator Owners as included and explained in the
Implementation Plan. One commenter suggested that one year would be sufficient because most lines will be short,
but the SDT pointed out that the distances of the lines can vary, and Generator Owners that have not been
practicing any sort of vegetation management will need to hire new staff and develop a full vegetation management
plan, which could take longer than the year given to Transmission Owners for implementation of FAC-003-1. No
changes were made to the two-year compliance timeframe, although the team has modified FAC-003-3’s
implementation plan to account for a few different scenarios that could occur with respect to the filing of FAC-003-2
and FAC-003-3
Organization
Ingleside Cogeneration LP
Yes or
No
Question 5 Comment
No
The two year compliance time frame makes sense only for those GOs who own
interconnections into critical generation facilities. See our response under Question #3.
Response: Thank you for your comment. It is unclear whether you find the two year timeframe too long or too short, or if you
believe that the standard should only apply to Generator Owners who own interconnections into critical generation facilities. No
change made.
Please see our response to your comments under Question 3 above.
APS
No
Leave GOs out of the standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
Arizona Public Service
Company
No
The generator should be able to be in compliance within one year since the distance of
line miles is small.
Response: Thank you for your comment. The distances of the lines can vary, and Generator Owners that have not been practicing
any sort of vegetation management will need to hire new staff and develop a full vegetation management plan, which could take
Project 2010-07 Consideration of Comments
53
Organization
Yes or
No
Question 5 Comment
longer than the year given to Transmission Owners for implementation of FAC-003-1. No change made.
Notheast Power
Coordinating Council
Yes
SERC OC Standards Review
Group
Yes
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
SPP Reliability Standards
Development Team
Yes
PPL Supply Group
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
Project 2010-07 Consideration of Comments
54
Organization
Yes or
No
EPSA
Yes
PacifiCorp
Yes
Westar Energy
Yes
Southern Company
Yes
Luminant Power
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Georgia Transmission
Corporation
Yes
BGE
Yes
Exelom
Yes
Wisconsin Electric
Yes
Duke Energy
Yes
Project 2010-07 Consideration of Comments
Question 5 Comment
No comment.
55
Organization
Yes or
No
Constellation Power
Generation
Yes
Ameren
Yes
Indeck Energy Services
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Generation LLC
Yes
Question 5 Comment
Utility Services, Inc.
LG&E and KU Energy
Tacoma Power
Manitoba Hydro
American Transmission
Company
Project 2010-07 Consideration of Comments
56
6. In its background resource document, the drafting team lists the standards that it has not modified, and offers
rationale for its decisions. Are there any reliability standards or requirements that you believe should apply to
Generator Owners or Generator Operators that own and are responsible for the operation of an overhead Facility,
that are not already applicable or have been proposed to be applicable (FAC-001 and FAC-003) by the Project 201007 drafting team? If so, please list them and offer an explanation as to why they should be applicable to that entity.
Summary Consideration: The SDT thanks all stakeholders for their feedback. The majority of commenters did not
suggest the addition of any standards or requirements to the team’s scope of work, and a few commenters cautioned
strongly against any additions. Some commenters suggested that the team consider including those standards and
requirements listed in the June 2011 Cedar Creek and Milford FERC orders. The drafting team has considered the
inclusion of the requirements listed in the Cedar Creek and Milford orders in the past, and has been revisiting them
throughout our process. They have continued to conclude, with stakeholder support, that no additional substantive
standard or requirement changes are necessary to achieve the goal of this project. With this posting, the drafting
team has revisited those standards yet again and developed a comprehensive document and spreadsheet tracing
their rationale (at every stage of the process) for not including additional standards or requirements. The team has
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other
standard.
While the SDT will not be adding standards at this time because they do not believe such additions are technically
justified or justified by stakeholder comments, the team will be seeking some additional informal feedback from
industry groups to ensure that their technical justifications are sound and supported by others outside of the drafting
team. The team has posted their current draft rationale and technical justification documents on the project webpage
with this posting. If you have any specific feedback on these documents, you are welcome to email
mallory.huggins@nerc.net.
Organization
Manitoba Hydro
Yes or
No
Question 6 Comment
No
The direction of the background resource document gives special treatment to the
Generator Owner in that it allows the Generator Owner TO status for a couple of
standards (FAC-001 and FAC-003), but exempts the Generator Owner from many of the
standards applicable to a TO. The NERC Functional Model defines the various functional
entities. If a Generator Owner wants to be a TO, all the Requirements applicable to a TO
should apply. There is no need to change specific Reliability Standards to allow the
Project 2010-07 Consideration of Comments
57
Organization
Yes or
No
Question 6 Comment
Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The purpose of the drafting team is “To propose a set of changes to existing
requirements and definitions, as well as additional requirements and definitions, that collectively adds significant clarity to
Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the interconnected
grid. This global strategy is proposed to expedite the closing of the reliability gap.” The SDT is applying select Transmission Owner
standards to Generator Owners, not attempting to give them TO status.
Sempra Generation
No
No, Sempra Generation believes the Project 2010-07 Team has effectively indentified the
Standards and Requirements that should apply to Generator Owners or Generator
Operators that own, and are responsible for, the operation of an overhead Facility, that
are not already applicable or have been proposed to be applicable.
Response: Thank you for your comment.
APS
No
Leave GOs and GOPs out of the FAC-001 and FAC-003 standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
SERC OC Standards
Review Group
No
Electric Market Policy
No
SERC Planning Standards
Subcommittee
No
Imperial Irrigation District
(IID)
No
SPP Reliability Standards
No
Project 2010-07 Consideration of Comments
58
Organization
Yes or
No
Question 6 Comment
Development Team
ACES Power Members
No
EPSA
No
PacifiCorp
No
Arizona Public Service
Company
No
Westar Energy
No
Luminant Power
No
American Electric Power
No
BP Wind Energy North
America Inc.
No
Tri-State Generation and
Transmission, Inc.
No
Xcel Energy
No
Georgia Transmission
Corporation
No
BGE
No
Exelom
No
Project 2010-07 Consideration of Comments
No comment.
59
Organization
Yes or
No
Ingleside Cogeneration LP
No
Wisconsin Electric
No
Duke Energy
No
Constellation Power
Generation
No
Ameren
No
Indeck Energy Services
No
CHPD
No
Independent Electricity
System Operator
No
FirstEnergy Corp
No
TransAlta Centralia
Generation LLC
No
Public Service Enterprise
Group
Yes
Question 6 Comment
FERC’s Cedar Creek and Milford order (issued on June 16, 2011 and that is posted at
http://www.nerc.com/files/Order_Denying_Appeals_RC11-1_RC11-2_20110616.pdf)
listed several standards (in Paragraphs 71 and 87) that should be applicable to Cedar
Creek and Milford, respectively. Because of this order, the drafting team should
examine the listed standards and determine whether they are or are not applicable to
Generator Owners or Generator Operators that own and are responsible for the
operation of an overhead Facility. We emphasize that our recommendation takes no
position on any legal issues regarding the referenced order.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Project 2010-07 Consideration of Comments
60
Organization
Yes or
No
Question 6 Comment
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We have
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. Please
see the accompanying resource documents for more information.
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
In FERC order "Denying Appeals of Electric Reliability Organization Registration
Determinations" dated June 16, 2011 (RC11-1 and RC11-2) FERC explicitly stated
compliance GAPs existed with the following standards at a minimum: o FAC-011,
Requirements R2, R2.1, R2.2. o PRC-001-1, Requirements R2, R2.2, R4; o PRC-004-1
Requirement R1; o TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4; o PER-0031, Requirements R1, R1.1, R1.2; o FAC-003-1, Requirements R1, R2; o TOP-001,
Requirement R1 and o FAC-014-2, Requirement R2. When a GO/GOP owns
transmission equipment but is not registered as a TO or TOP. The drafting team should
explicitly address each of these the above requirements.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We have
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. Please
see the accompanying resource documents for more information.
Tacoma Power
Yes
Tacoma Power suggests that three standards be reconsidered for inclusion in this
Project, to include the Generator Owner and/or Operator: EOP-005, more directly
responsible for participation in restoration plans; PER-002, responsible for training; and
VAR-001.
Response: Thank you for your comment. We have considered the inclusion of additional standards and requirements throughout
our process and we continue to conclude, with stakeholder support, that no additional substantive standard or requirement changes
are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those standards yet again and
developed a comprehensive document and spreadsheet tracing our rationale (at every stage of the process) for not including
Project 2010-07 Consideration of Comments
61
Organization
Yes or
No
Question 6 Comment
additional standards or requirements. We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the
applicability of that or any other standard. Please see the accompanying resource documents for more information. The SDT does
not agree that VAR-001 should be applied to a GOP as VAR-002 @R2 already requires the GOP to “maintain the generator voltage
or Reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.” We believe this is sufficient
in meeting the purpose of VAR-001.
Southern Company
Yes
Bonneville Power
Administration
Yes
Please see our Comments in response to Question 7.
PPL Supply Group
Notheast Power
Coordinating Council
LG&E and KU Energy
Utility Services, Inc.
American Transmission
Company
Project 2010-07 Consideration of Comments
62
7. Do you have any other questions or concerns with the proposed standards or with the background resource
document that have not been addressed? If yes, please explain.
Summary Consideration: The SDT thanks all stakeholders who offered additional feedback in this section. Some
comments revisited issues that had been addressed in other questions, and other comments introduced new minority
concerns.
A few commenters suggested, again, the inclusion of definitions or additional standards within the scope of this
project, and the SDT appreciates those comments, especially those which included detailed suggestions. While the
team is not proposing any definition changes with this round of updated standard changes, they do plan to consider
some definition changes or possibly new definitions to prevent future unnecessary registration of GOs and GOPs as
TOs and TOPs and ensure that there are no possible reliability gaps. In the next steps of our project, we will consider
putting forward definition-related changes for comment separately, following the procedure approved by the
Standards Committee after its July 2011 meeting.
The SDT has also considered the inclusion of additional standards and requirements throughout our process and
continues continue to conclude, with stakeholder support, that no additional substantive standard or requirement
changes are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those
standards yet again and developed a comprehensive document and spreadsheet tracing our rationale (at every stage
of the process) for not including additional standards or requirements. The team has elected to propose a slight
clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. They have
attempted to make our technical justifications much more robust and comprehensive than they were in the past, as
suggested by stakeholders. Please see the accompanying resource documents (posted on the project webpage) for
more information.
One commenter expressed concern about whether the SDT’s work would be approved by regulators. The drafting
team is doing everything we can to work with regulating entities to ensure that forced registrations no longer occur.
For most of the comments, the team made no changes and explained why:
One commenter suggested modifying the definition of Right-of-Way in the currently approved FAC-003-1 (our FAC003-X). The team could not make any change because the definition proposed in FAC-003-3 has not been formally
approved and, in general, modifications to the definition of ROW are outside the scope of our team.
One commenter suggested modifications to the format of the requirements in FAC-003-X, which the SDT determined
to be outside its scope.
Project 2010-07 Consideration of Comments
63
One commenter expressed concern about a Transmission Owner or Generator Owner having to comply with FAC-003
for a Facility that it did not own. The drafting team does not know why a Transmission Owner or Generator Owner
would ever be required to provide evidence, documentation, notification, or inspection of vegetation management for
Facilities not owned by that registered entity, except where explicitly agreed upon in a contract. In the absence of
additional information to clarify this commenters concern, the SDT does not believe this needs to be addressed
within the standard.
One commenter focused on FAC-001 and expressed concern about the “activation” point of the standard and the
feasibility of any interconnection. The SDT reminded the commenter that “activation only occurs with an executed
Agreement, and that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their Facilities.
One commenter wondered why only a select set of TO/TOP requirements were being applied to GOs/GOPs. The SDT
directed this commenter to the goal of the team, which is to apply select Transmission Owner standards to Generator
Owners, not to give them TO status.
Organization
TransAlta Centralia
Generation LLC
Yes or
No
No
Question 7 Comment
TransAlta Centralia Generation LLC (TransAlta) supports the recommendations put
forward by the Project 2010-07 drafting team. The implementation of these
recommendations will provide for much needed certainty for owners and operators of
generation facilities.
Response: Thank you for your comment.
SERC Planning Standards
Subcommittee
No
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers.
Response: Thank you for your comment.
CHPD
No
BP Wind Energy North
No
Project 2010-07 Consideration of Comments
64
Organization
Yes or
No
Question 7 Comment
America Inc.
Ameren
No
Independent Electricity
System Operator
No
Tri-State Generation and
Transmission, Inc.
No
Electric Market Policy
No
Georgia Transmission
Corporation
No
BGE
No
Duke Energy
No
SPP Reliability Standards
Development Team
No
Imperial Irrigation District
(IID)
No
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
No
Xcel Energy
No
Luminant Power
No
Project 2010-07 Consideration of Comments
No comment.
65
Organization
Yes or
No
Wisconsin Electric
No
ACES Power Members
No
Arizona Public Service
Company
No
Westar Energy
No
Bonneville Power
Administration
No
SERC OC Standards Review
Group
No
Notheast Power
Coordinating Council
Yes
Question 7 Comment
Regarding the Right-of-Way definitions, the definition in FAC-003-3 is the better of the
two. Suggest adding “and maintain” to the first sentence of the definition as follows:
The corridor of land under a transmission line(s) needed to operate and maintain the
line(s). The width of the corridor is established by engineering or construction
standards as documented in either construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect when the line was built. The
ROW width in no case exceeds the applicable Transmission Owner’s or applicable
Generator Owner’s legal rights but may be less based on the aforementioned criteria.
The term Right-of-Way goes beyond Transmission Vegetation Management, and that
should be considered in the definition. How does Right-of-Way affect transmission
facilities that are routed over bodies of water, or over valleys, highways, etc.? Rightof-Way in relation to underground facilities? The format of FAC-003-X should be made
consistent with current NERC guidelines (i.e.--Parts of Requirements should not have
R’s in their numbering, should be 1.1, 1.2 etc.).
Response: Thank you for your comment. It would be outside the scope of this team to modify the definition of Right-of-Way in the
currently approved FAC-003-1 (our FAC-003-X), because the definition proposed in FAC-003-3 has not been formally approved and,
in general, modifications to the definition of ROW are outside the scope of our team. No change made.
Project 2010-07 Consideration of Comments
66
Organization
Yes or
No
Question 7 Comment
With respect to the changes to the format of the requirements in FAC-003-X, while our drafting team is making changes to update
the format of the standard where possible, we do not think it is appropriate to change the listing of the sub-requirements to parts.
In earlier versions of standards, the sub-requirements were written as requirements (for instance, they have their own VSLs), and
we do not believe it is appropriate within our scope to make that format and labeling change.
Public Service Enterprise
Group
Yes
While we generally agree with the drafting team’s modifications to these standards, the
team’s approach may not directly resolve the fundamental registration issue regarding
a Generation Owner that only owns non-integrated interconnection transmission
facilities. The non-integrated interconnection transmission facilities owned by a GO are
part of the Bulk Electric System (BES) because they are part of BES generation
facilities. The ownership of these non-integrated facilities should not require a GO to
also register as a Transmission Owner. The draft team has proposed modifying two
FAC standards that would apply to such GO-owned interconnection transmission
facilities. These GO-owned interconnection transmission facilities are not, however,
“integrated” transmission facilities, as the drafting team correctly points out in its
background resource document. A proposed solution to the Generation Owner
registration issue is discussed below.
NERC’s Rules of Procedure (ROP) require entities to be registered in accordance with
the definitions in the NERC Glossary of Terms Used in Reliability Standards (Glossary)
and in accordance with the NERC Statement of Compliance Registry Criteria document.
The Glossary has these definitions:
o Generation Owner - Entity that owns and maintains generating units.
o Transmission Owner - The entity that owns and maintains transmission
facilities.
o Facility - A set of electrical equipment that operates as a single Bulk Electric
System Element (e.g., a line, a generator, a shunt compensator, transformer,
etc.)
o Transmission - An interconnected group of lines and associated equipment for
the movement or transfer of electric energy between points of supply and points
at which it is transformed for delivery to customers or is delivered to other
electric systems.
Project 2010-07 Consideration of Comments
67
Organization
Yes or
No
Question 7 Comment
o Transmission Service - Services provided to the Transmission Customer by the
Transmission Service Provider to move energy from a Point of Receipt to a Point
of Delivery
The drafting team should create a new definition for the term “integrated transmission
facilities” and include this new definition in the Glossary. This definition should then be
use to modify the definition of Generation Owner so that registration will be clear.
While the team chose not to create any new definitions, we believe the registration
issue cannot be resolved without modifying the definition of “Generation Owner.”
The following definition is proposed for Integrated Transmission Facilities in the NERC
Glossary:
o Integrated Transmission Facilities (ITF) - ITF are the Facilities that are a subpart
of Transmission system that are capable of carrying the flows from multiple
generator plants at different points of interconnection for delivery to customers or
to other electric systems
This proposed ITF definition builds upon FERC precedent in the Open Access
Transmission Tariff (OATT) area. FERC has recognized that facilities that can carry
flows from multiple supply points and deliver that power to either customers or other
electric systems are proper facilities to include in an OATT and define the “Transmission
System” for OATT purposes. The term “Transmission System” is an OATT-defined term
that means “The facilities owned, controlled or operated by the Transmission Provider
that are used to provide transmission service under Part II [Point-to-Point Transmission
Service] and Part III [Network Integrated Transmission Service] of the Tariff.” Under
FERC’s precedent, facilities such as generator step-up transformers and generator
interconnecting transmission facilities have been excluded from the OATT; i.e., they are
not facilities that provide Transmission Service because they cannot carry the flows
from multiple supply points for delivery to customers or other electric system - their
only use is to the Generation Owner. They perform two functions for a GO:
1. They deliver power from the GO’s generators at a site to the OATT-defined
Transmission System, and
2. They deliver off-site power from the OATT-defined Transmission System to the
generators at a site when the generators at a site are not operating.
Project 2010-07 Consideration of Comments
68
Organization
Yes or
No
Question 7 Comment
While building on FERC OATT precedent, the proposed definition of “Integrated
Transmission Facilities” does not require an applicable Transmission Service tariff to
identify those facilities. Integrated Transmission Facilities are simply defined as those
that capable of carrying flows from multiple supply points for delivery to customers or
to other electric systems. Using the ITF definition, the definition of Generation Owner
could be modified as follows:
o Generation Owner - Entity that owns and maintains generating units but which
does not own or maintain Integrated Transmission Facilities.
Response: Thank you for your comment. We appreciate the detailed suggestions. While we are not proposing any definition
changes with this round of updated standard changes, we do plan to consider some definition changes or possibly new definitions to
prevent future registration and ensure that there are no possible gaps. In the next steps of our project, we will consider putting
forward definition-related changes for comment separately, as is now allowed by the Standards Committee after its July 2011
meeting.
EPSA
Yes
EPSA can appreciate the SDT’s decision that it not propose new defined terms for the
NERC Glossary. The SDT bases the decision on outreach meetings with NERC, regional
compliance managers and industry organizations. EPSA supports outreach but still
believes that the SDT should propose definitions for the NERC Glossary. The definitions
can serve as a basis for the outreach meetings while also further limiting reliability gaps
- real or perceived. Much as EPSA expressed in its White Paper comments there is still
a need for a definition for generator interconnection facilities. In addition, because
integrated transmission facility has also played a big part in the cases that have
prompted the need for Project 2010-07 the drafting team should propose a glossary
change for that definition as well. A definition for generation interconnection facilities is
necessary in Project 2010-07 Standard so that the interface between generators and
transmission system can be clearly established and any ambiguities about reliability
responsibilities for GOs & GOPs and TO & TOPs can be eliminated.
EPSA recommended the definitions from the Ad-Hoc Group Report could be used for
incorporating the Generator Interconnection Facility into the standard:
Generator Interconnection Facility - Sole-use facility for the purpose of connecting
the generating unit(s) to the transmission grid. In this regard, the sole-use facility
Project 2010-07 Consideration of Comments
69
Organization
Yes or
No
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only transmits power associated with the interconnecting generator, whether
delivered to the grid or delivered to the generator for station service or auxiliary
load, or delivered to meet cogeneration load requirements.
Generator Interconnection Operational Interface - Location at which operating
responsibility for the Generator Interconnection Facility changes between the
Transmission Operator and the Generator Operator.
These definitions were developed with due consideration for varying configurations,
outages, and generators materiality to the BES. The Facility definition defines the
purpose of the facility, while the Generator Interconnection Operational Interface
definition provides the functional lines of demarcation between the GO and the TO. The
definitions were developed based on the purpose of generator interconnection facilities,
their usage and how their usage differs from transmission facilities that comprise the
interconnected grid. Similar to EPSA’s assertions on the White Paper competitive
suppliers believe this is a sound basis for distinguishing BES facilities. EPSA also
suggests that the SDT include the following proposed definition for Integrated
Transmission Facilities for inclusion in the NERC Glossary:
Integrated Transmission Facilities (ITF) - ITF are the Facilities that are a subpart
of Transmission system that are capable of carrying the flows from multiple
generator plants at different points of interconnection for delivery to customers,
or to other electric systems.
This proposed ITF definition builds upon Commission precedent in the Open Access
Transmission Tariff (OATT) area. FERC has recognized that facilities that can carry
flows from multiple supply points and deliver that power to either customers or other
electric systems are proper facilities to include in an OATT and define the “Transmission
System” for OATT purposes. The term “Transmission System” is an OATT-defined term
that means “The facilities owned, controlled or operated by the Transmission Provider
that are used to provide transmission service under Part II [Point-to-Point Transmission
Service] and Part III [Network Integrated Transmission Service] of the Tariff.” Under
Commission precedent, facilities such as generator step-up transformers and generator
interconnecting transmission facilities have been excluded from the OATT; i.e., they are
not facilities that provide Transmission Service because they cannot carry the flows
from multiple supply points for delivery to customers or other electric system - their
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only use is to the GO and perform two functions:
1. They deliver power from the GO’s generators at a site to the OATT-defined
Transmission System, and
2. They deliver off-site power from the OATT-defined Transmission System to the
generators at a site when the generators at a site are not operating.
While building on FERC OATT precedent, the proposed definition of “Integrated
Transmission Facilities” does not require an applicable Transmission Service tariff to
identify those facilities. Integrated Transmission Facilities are simply defined as those
that capable of carrying flows from multiple supply points for delivery to customers or
to other electric systems. Using the ITF definition, the definition of Generation Owner
could be modified as follows:
Generation Owner - The Entity that owns and maintains generating units but
which does not own or maintain Integrated Transmission Facilities.
EPSA encourages the Project 2010-07 SDT to consider fitting the above definitions into
the current proposal for inclusion in the NERC Glossary. Therefore, EPSA respectfully
requests that the SDT for Project 2010-07 consider the all the recommendations made
herein to the seven questions.
Response: Thank you for your comment. We appreciate the detailed suggestions. While we are not proposing any definition
changes with this round of updated standard changes, we do plan to propose some definition changes or possibly new definitions to
prevent registration and ensure that there are no possible gaps. In the next steps of our project, we will consider putting forward
definition-related changes for comment separately, as is now allowed by the Standards Committee after its July 2011 meeting
PacifiCorp
Yes
PacifiCorp believes the Standards Drafting Team should clarify the Transmission Owner
and/or the Generator Owner are not required to provide evidence, documentation,
notification, or inspection of vegetation management for facilities not owned by the
Transmission Owner and/or the Generator Owner.
Response: Thank you for your comment. The drafting team does not know why a Transmission Owner or Generator Owner would
ever be required to provide evidence, documentation, notification, or inspection of vegetation management for Facilities not owned
by that registered entity, except where explicitly agreed upon in a contract. We do not believe this needs to be addressed within the
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Yes
(1) The SDT needs to review the June 16, 2011 FERC Order on Cedar Creek and Milford
and factor this into the equation. The FERC Order concludes that the Cedar Creek and
Milford entities must register as a TO and TOP. In addition to FAC-003, the Cedar
Creek and Milford order lists the following standards and requirements that apply to
these entities as a TO/TOP:
standard. No change made.
Southern Company
o PER-003-1, R1, R1.1, R1.2 (requiring NERC-certified transmission operators);
o PRC-001-1, R2, R2.2, R4, R6 (notification of relay or equipment failures);
o PRC-004-1, R1 (analyzing protection system misoperations);
o FAC-014-2, R2 (establishment of system operating limits);
o TOP-001, R1 (authority to take actions to alleviate operating emergencies);
o TOP-004-2, R6, R6.1, R6.2, R6.3, R6.4 (establishment of formal policies to
address voltage levels, planned outages, switching, Interconnection Reliability
Operating Limits, and System Operating Limits).
The SDT needs to address these specific requirements in sufficient detail by either
revising the Project 2010-07 Background Resource Document or proposing revisions to
these standards to address any reliability gaps. For example, we recommend, as a
minimum, that the Background Resource Document discussion under PRC-001-1 be
revised to state (underlined text added), “Generator Operators and the scope of
protection equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirements R1, R2, R3, and R5.” Please note that
this statement, even with our proposed revision, conflicts with the FERC Order on Cedar
Creek and Milford, Paragraphs 64, 65, and 78 where FERC states that Cedar Creek and
Milford must register as a TO and TOP to ensure the protection system coordination
requirements in R2 and R4 of PRC-001 are met. Thus, the discussion for PRC-001-1 in
the Project 2010-07 Background Resource Document needs additional language to
demonstrate adequacy of the GO requirements in order to prevent GOs that own
generation interconnection Facilities from having to register as a TO and TOP.
(2) In addition, we believe the SDT should add supporting discussion to the
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Background Resource Document to explain why the following standards adequately
cover GO/GOP requirements at the Transmission Interface: PRC-004-2, PRC-005-1,
PRC-023-1. For example, the Background Resource Document could state that PRC023-1 Section A.4 Applicability already includes, “4.2. Generator Owners with loadresponsive phase protection systems as described in Attachment A, applied to facilities
defined in 4.1.1 through 4.1.4.”
(3) Furthermore, FERC’s analysis in the Cedar Creek and Milford order suggests that
reliability gaps will occur if certain entities are not registered as TO/TOP. The GRTI SAR
DT should assess why its findings are different from the Commission’s findings. By way
of background, the GRTI SAR DT provides that its own assessment of the GOTO Ad Hoc
Group Final Report concludes with a belief that there are only two standards requiring
modifications to address reliability gaps - FAC-001 and FAC-003 (Background Resource
Document, page 3). FERC will most likely require that NERC clearly demonstrate and
provide technical support for the position that GO’s only need to comply with FAC-001
and FAC-003 and not the other standards noted by FERC. The Background Resource
Document does not appear to provide adequate technical support for the GRTI SAR DT
position. Therefore, the GRTI SAR DT should develop that technical support in
preparation for the filing of these revised standards at FERC.
Response: Thank you for your comment. We have considered the inclusion of additional standards and requirements throughout
our process and we continue to conclude, with stakeholder support, that no additional substantive standard or requirement changes
are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those standards yet again and
developed a comprehensive document and spreadsheet tracing our rationale (at every stage of the process) for not including
additional standards or requirements. We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the
applicability of that or any other standard. We have attempted to make our technical justifications much more robust and
comprehensive than they were in the past, as you suggest. Please see the accompanying resource documents for more information.
APS
Yes
Leave GOs out of the standards, because it just adds more regulation and reporting
requirements not needed.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
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Sempra Generation
Yes or
No
Question 7 Comment
Yes
When implemented, the recommendations of the Project 2010-07 Team go a long way
toward providing the regulatory and compliance certainty needed by generators who
own or operate Generator Interconnection Facilities. NERC is encouraged to provide
these industry-supported amendments to the NERC Board of Trustees in the near
future. Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment.
Exelon
Yes
FAC-001-1. Exelon has generating stations that have the Main Power Transformer
(MPT) disconnect as the point of demarcation. The station owns the short leads from
the MPT disconnect back to the generator and the applicable TO owns from the MPT
disconnect up to and including the switchyard. It is not practical for another entity to
request to interconnect to the MPT disconnect nor should it be allowed. The SDT
should consider verbiage to the standard that does not allow requests to interconnect
to a MPT disconnect. 2. Exelon is having difficulty determining how this standard would
apply to GOs and how GOs would implement the standard; suggest that examples be
provided in an implementation document specifically showing where and how this
standard would apply.
Response: Thank you for your comment.
(1) FAC-001-1 would not be “activated” simply with another entity’s request to interconnect. The standard is “activated” only with
an executed Agreement to evaluate the reliability impact of interconnection. If another entity cannot interconnect to the MPT, the
process should not get to the point of an executed Agreement and thus this standard would never apply.
(2) In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have received or
have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is important to clarify the
responsibilities related to such a request in NERC’s Reliability Standards by including applicable Generator Owners in FAC-001-1. We
have documented our technical justification in an accompanying resource document and encourage you to review it.
Ingleside Cogeneration LP
Yes
Project 2010-07 Consideration of Comments
There is a fundamental issue related to the interconnection of generation and
distribution facilities into the transmission grid. There is a myriad of complex
architectures which make the designation of ownership and operational responsibilities
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unclear in both cases. Both this team’s efforts and those by the project team
redefining the extent of the BES have run into this issue.
Ingleside Cogeneration LP recognizes that the effort to properly assign reliability
responsibilities in these gray-area connections is difficult. However, pushing the issue
back to the GO/GOP by looking for them to jointly determine responsibilities with
adjacent entities will create every conceivable arrangement possible.
It seems like it should be possible to address a handful of common interconnection
configurations at the start. As knowledge builds, perhaps other architectures could be
added. This seems to be the direction that the project team redefining the extent of
the BES is heading.
Lastly, we need some assurance that regulators will work with us as we go down this
path. Right now, the feeling is that they will continue to use forced registrations as a
hammer - which may render moot this team’s efforts anyways.
Response: Thank you for your comment.
The drafting team is doing its best to coordinate with regulators to ensure that forced registrations no longer occur. While we can
never be sure exactly what decision the regulators will make, our intent is to make changes through this project that prevent any
future forced registrations. We have encouraged regulators to provide formal comments if they believe our changes are not going to
close the gap. While there can be similarities, the SDT believes that each interconnection agreement is different. The SDT believes
that each party to such agreement should have identified its ownership and operational responsibilities. If there is uncertainty as to
ownership of operational responsibility of a Facility used to interconnect a generator, the respective GO/GOPs and TO/TOPs should
be addressing these. Resolving these uncertainties can only occur between the affected parties.
Manitoba Hydro
Yes
Project 2010-07 Consideration of Comments
The direction of the background resource document gives special treatment to the
Generator Owner in that it allows the Generator Owner TO status for a couple of
standards (FAC-001 and FAC-003), but exempts the Generator Owner from many of
the standards applicable to a TO. A Generator Owner that owns BES transmission
should be held accountable for the specific Requirements and Reliability Standards
applicable to the TO and Transmission Operator functions. If no other entity assumes
accountability for these specific Requirements and Reliability Standards on the
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Generator Owner BES transmission (for example system operation, protection and
communication), there will be a reliability gap. Improper operation, coordination and
protection of the Generator Owner BES transmission could have an impact on reliability.
Response: Thank you for your comment. The purpose of the drafting team is “To propose a set of changes to existing
requirements and definitions, as well as additional requirements and definitions, that collectively adds significant clarity to
Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the interconnected
grid. This global strategy is proposed to expedite the closing of the reliability gap.” The SDT is applying select Transmission Owner
standards to Generator Owners, not attempting to give them TO status. The SDT believes that each interconnection agreement is
different. The SDT believes that each party to such agreement should have identified its ownership and operational responsibilities.
If there is uncertainty as to ownership of operational responsibility of a Facility used to interconnect a generator, the respective
GO/GOPs and TO/TOPs should be addressing these. Resolving these uncertainties can only occur between the affected parties.
Constellation Power
Generation
Yes
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The recent FERC Order concerning
Cedar Creek and Milford wind suggested that the list of applicable standards needing
revision should go beyond FAC-001 and FAC-003.
We appreciate the discussion and concerns raised by FERC in the order; however, the
discussion is limited by failing to consider these issues in light of the full package of
existing standards. Below is a look at the FERC suggested standards and how they
intersect with other standards:
o PRC-001-1, Requirements R2, R2.2, R4; FERC expressed concern that certain
protection system components may not be well coordinated with the RC.
However, the same standard (PRC-1) addresses this issue by requiring all GOs to
ensure coordination of their protection system with interconnected parties.
Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA,
etc.
o PRC-004-1 Requirement R1; FERC expressed concern that certain protection
system components may not be analyzed for misoperations. However, the same
standard (PRC-4) addresses this issue by requiring all GOs to ensure that they
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analyze all misoperations on their protection system which would include the
protection of the tie line.
o TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4; FERC expressed concern
that coordination may be lacking between a GO and a TO with regards to the
generator tie line. However, TOP standards applicable to GOs address this issue
by requiring all GOs to coordinate all maintenance and emergency outages (both
forced and planned) with all applicable interconnected parties. Further, all ISO
procedures require the same of GOs.
o PER-003-1, Requirements R1, R1.1, R1.2; FERC expressed concern that certain
generator operators are responsible for the real time operation of the
interconnected BES without being NERC certified operators, potentially causing a
reliability gap. Generator Operators do not monitor and control the BES, they
control and monitor generators that it operates and relays information to other
operating entities. Therefore, NERC certification is not required.
o FAC-003-1, Requirements R1, R2; FERC and the drafting team seem aligned in
the need to revise this standard and the revision proposal includes such a
revision.
o TOP-001, Requirement R1; FERC expressed concern that certain tie lines may
not be required to operate in such a way as to alleviate operational emergencies.
However, IRO and TOP standards applicable to GOs address this issue by
requiring all GOs to operate as directed by their TOP, BA, or RC as directed and
must render emergency assistance.
o FAC-014-2, Requirement R2; FERC expressed concern that certain tie lines may
have a rating based on a methodology that may not be consistent with the
methodology used by the RC. However, standards FAC-8 and FAC-9 address this
issue by requiring all GOs to develop a methodology to rate all equipment, and
that the RC has the authority to challenge the GO on that methodology. The onus
is on the GO to either change their methodology and rating accordingly, or
provide a technical justification as to why they cannot adopt the changes. Further,
a generator will never be limited by its tie line, as a generator’s profits are
directly tied to its output. Therefore no generator would limit its facility to the
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equipment that is delivering that output.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We
appreciate the rationale you have included within your comment, and where we agree, we have incorporated it into our own.
We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other
standard. Please see the accompanying resource documents for more information.
Utility Services, Inc.
Yes
In one of the supporting documents for the upcoming comments, the GO/TO group
included the following statement in support for the rationale on FAC-001. In its first
posting for informal comment, the drafting team set the “trigger” for the application of
FAC-001 as the receipt of a request for interconnection. Many commenters disagreed
with this approach and suggested that the “trigger” be based upon “the intent or
obligation” to interconnect a new Facility to an existing interconnecting Facility that is
owned by a generator. Accordingly, the drafting team has proposed language to
addresses this concern. The intent of this modified language is to start the compliance
clock at such time as the Generator Owner executes an Agreement to perform the
reliability assessment required in FAC-002-1. This step should occur whether the
generator voluntarily agrees to the interconnection request or is compelled by a
regulatory body to do so. In either case, we expect the Generator Owner and the
requestor to execute some form of Agreement. We intentionally excluded a specific
reference to the form of Agreement (such as a feasibility study) in deference to
comments that we should avoid comingling of commercial and reliability aspects in
reliability standards.
I wonder about whether or not this can work timing-wise. It says the compliance clock
starts with the agreement to perform the reliability assessment for FAC-002. The FAC001 requirements outline the need for a registered entity to document, maintain, and
publish facility connections requirements in order to be compliant. If the clock starts at
the agreement for the assessment, does that mean that you then document, maintain,
and publish the connection requirements? Don’t the connection requirements usually
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outline the terms for the “agreement for the assessment”? I am not sure that I
understand the timing sequence in order to be compliant to the standard. I would think
that the agreement needs to be in place at the time of the effective date of the
standard, not upon an application.
Response: Thank you for your comment. We have provided a detailed explanation of how this process might look in the
accompanying FAC-001-1 technical justification. Please refer to that for more information.
FirstEnergy Corp
Yes
The June 16, 2011 FERC Order denying the appeals of two wind generating facilitiesCedar Creek and Milford - of the NERC determinations that Cedar Creek and Milford
must each be registered as a transmission owner and transmission operator on the
NERC Compliance Registry complicates the GO-TO drafting team’s work. However, the
issues may be distinct and different in the end. The existing GO-TO team’s work
product defines new reliability expectations for a generator owner regardless of
whether or not the same entity is also being required to have a TO-TOP “light”
compliance registration. In the Order, FERC describes what it believes are an
appropriate limited set of TO-TOP requirements when a TO-TOP “light” registrations is
deemed warranted for a traditional generation owner. The drafting team should
describe what, if any, impact the FERC June 16 Order is having on its work scope.
One minor comment for the background resource document. On page one, the last
sentence of the 1st paragraph which currently reads “ ... appropriate level of reliability
for the BES.” Consider changing to read “ ... Adequate Level of Reliability for the BES.”
And, include a footnote directing the reader to NERC’s definition/paper describing ALR.
The later references to “adequate level of reliability” within the document (i.e. page 2,
2nd paragraph could then be reduced to the acronym ALR.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements.
Thank you for pointing out the opportunity to use the term “Adequate Level of Reliability.” Because NERC has appointed a task force
to explore whether that definition of Adequate Level of Reliability needs to be changed, we are avoiding references to it in our latest
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resource document.
PPL Supply Group
Yes
American Wind Energy
Association
The American Wind Energy Association (AWEA) appreciates the opportunity to
submit these formal comments on the NERC Project 2010-07. AWEA supports the
general direction indicated by both the Generator Requirements at the Transmission
Interface Ad Hoc Group (GOTO Ad Hoc Group), and the Project 2010-07 Standards
Development Team (SDT). We agree with the sentiments from both groups that a
Generator Owner (GO) or Generator Operator (GOP) that also owns or operates a
generator interconnection facility (GIF), should not be required to register as a
Transmission Owner (TO) and/or Transmission Operator (TOP) strictly because they
own or operate the GIF. We also agree that requiring these GOs or GOPs to comply with
all the TO/TOP standards would have little effect on or benefits to reliability of the Bulk
Electric System.
AWEA supports the aim of these groups to address any reliability gap that may exist
with regard to GIFs by considering such facilities as part of the generating facility, and
therefore also subject to the GO/GOP standards. AWEA also supports the approach of
identifying a limited number of TO/TOP standards, such as FAC-001 and FAC-003,
which should also apply to GIFs. We would be concerned, however, if additional
requirements were added beyond these two, without serious consideration by the SDT
and additional industry experts. The recent FERC order on the required registration as
TOs and TOPs of two generator interconnection facilities may raise some question about
the direction that the GO/TO and the SDT have taken so far on this topic. AWEA urges
NERC and the SDT to use caution in considering any additional standards to apply to
GIFs as the current approach of the GO/TO and SDT efforts have been generally
supported. Consideration of any addition standards with respect to GIFs should be done
on a standard-by-standard basis, reviewing the applicability of each standard as well as
the impact on the reliability of the Bulk Electric System.
Response: Thank you for your comment. The drafting team has considered the inclusion of additional standards and requirements
in the past, and we have been revisiting them throughout our process. We continue to conclude, with stakeholder support, that no
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additional substantive standard or requirement changes are necessary to achieve the goal of this project. With this posting, the
drafting team has revisited those standards yet again and developed a comprehensive document and spreadsheet tracing our
rationale (at every stage of the process) for not including additional standards or requirements.
Cogeneration Association of
California
The resolution of this issue regarding generator interconnection facilities should compel a
certain result in determining how to classify and register generator tie-lines. Under the
current standards, NERC is compelled to register owners with generator tie-lines as
transmission owners. FERC has affirmed this. The changes to the standards should be
such that NERC and FERC are compelled to consider the tie-lines as part of the generator
facilities. The current proposal from this task force does not achieve that result. While
the proposal does make very appropriate changes to certain reliability standards, it does
not change the basic definition of the Bulk Electric System or change NERC’s Statement of
Compliance Registry Criteria, to determine how tie-lines are classified. Even though the
relevant reliability standards would be changed so that they are also applicable to
generator facilities, NERC and the regional entities will continue to apply the same
definition and criteria and can continue to classify the tie-lines as Transmission.
The solution is to change the BES definition and NERC Statement as well as changing the
applicability of the relevant reliability standards. The background resource document from
this group suggests that a change in the BES definition was part of the overall solution,
but the Project 2010-17 team did not address this in its proposed definition. The concept
paper from the 2010-17 group does include “generator interconnection line leads,” but the
formal definition paper does not.
This project group should include in its formal proposal a change to the definition of BES,
including generator interconnection facilities within the definition of generation.
Response: Thank you for your comment. While we are not proposing any definition changes with this round of updated standard
changes, we do plan to propose some definition changes or possibly new definitions to prevent registration and ensure that there
are no possible gaps. In the next steps of our project, we will consider putting forward definition-related changes for comment
separately, as is now allowed by the Standards Committee after its July 2011 meeting. Although this drafting team cannot itself
make changes to the Statement of Compliance Registry Criteria, our hope is that modifications to definitions would provide the
language and the impetus to make those Registry Criteria changes.
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While the Project 2010-07 SDT coordinated with the Project 2010-17 BES SDT very early on, the Project 2010-17 SDT elected not
to include any reference to generator interconnection Facilities within the definition of generation. We will consider making further
suggestions during future comment periods, and you should do the same.
American Electric Power
Tacoma Power
Indeck Energy Services
LG&E and KU Energy
American Transmission
Company
END OF REPORT
Project 2010-07 Consideration of Comments
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Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments for Project 2010-07—Generator Requirements at the Transmission Interface.
These standards were posted for a 45-day public comment period from October 5, 2011 through
November 18, 2011. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 40 sets of comments, including
comments from 123 different people from approximately 86 companies representing all 10 of the
Industry Segments as shown in the table on the following pages.
Based on stakeholder comments, the SDT made minor changes to FAC-001-1, FAC-003-X, FAC-003-3,
and PRC-004-2.1. The standards will proceed to recirculation ballot.
In FAC-001-1, the SDT corrected a typo in the Applicability section 4.2.1 to change “within” to “with”;
corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather
than just 3.1.1 through 3.1.6; and changed references to “Transmission System” to “interconnected
Transmission systems” to ensure consistency with the language elsewhere in the standard and in FAC002-1.
In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO exemption
in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and changed “RE” to
“Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements
at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either
(1) staffed and the overhead portion is within line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting these Facilities because
incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and appropriate risk prevention
approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead
transmission lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the
generating switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has
been agreed upon by the stakeholder body. In its Consideration of Comments report from the last
formal comment period, which ended on July 17, 2011, the SDT explained “We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the part
of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference here, the
SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Members of the ballot pool should note that for its recirculation ballot, the SDT will be balloting both
FAC-003-3 and FAC-003-X, but stakeholders should not vote as though they are choosing one or the
other. The SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved
by FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually.
In other words, stakeholders who support adding GOs to the applicability of FAC-003 should vote in
the affirmative for both FAC-003-3 and FAC-003-X.
In PRC-004-2.1, the SDT added a reference to the generator interconnection Facility to the data
retention section of the standard (for consistency with the language in R2) and corrected a typo in the
Version History.
Several commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same
explicit reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT
agrees and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation
ballot posting) soon.
Many commenters encouraged the SDT to reexamine the standards and requirements addressed in
FERC’s Milford and Cedar Creek orders and NERC staff’s draft compliance directive regarding generator
lead lines. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or draft NERC directives, within the standards process,
and until this round of comments, when NERC staff submitted comments, the SDT had no formal
mandate that would have made it appropriate to consider the content of the proposed directive.
The SDT reviewed all addressed standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these
standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder
concern, the SDT has expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or
by NERC in its draft compliance directive.
Other minority comments are addressed within specific questions below.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
2
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.) …. .............................................................. 12
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1? …. ........................................................................................... 29
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some
commenters found the half-mile length too short, others found it too long, and still others found
the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its
latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile
beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the
part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this
qualifier for Generator Owners because there is a very low risk from vegetation within the line of
sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a
decision that will be made as Project 2007-07—Vegetation Management moves forward, do you
support the proposed redline changes to FAC-003-X and FAC-003-3? …. ....................................... 34
4.
Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X? …. ......................................................................................... 50
5.
In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here. …. ...................................................................................... 57
6.
In its technical justification document, the SDT reviews all standards that had been proposed for
substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for any
of these decisions, please include suggested language here. …. ..................................................... 63
7.
The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
4
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the set
of standards currently posted achieve this goal? …. ......................................................................... 74
8.
If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the
appropriate ones? ….......................................................................................................................... 87
9.
If you answered “no” to Question 7, what standards need to be added or removed to achieve the
SDT’s goal? Please provide technical justification for your answer. …. ............................................ 91
10. Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 99
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
5
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Gerald Beckerle
SERC OC Standards Review Group
1.
Scott Brame
NCEMC
2.
Troy Willis
Georgia Transmission Corp. SERC 1
3.
Mike Hirst
Cogentrix
SERC 5
4.
Bob Dalrymple
TVA
SERC 1, 3, 5, 6
5.
Matt Carden
Southern Co.
SERC 1, 5
6.
Shardra Scott
Gulf Power Co.
SERC 3
7.
Kerry Sibley
Georgia Transmission Corp. SERC 1
8.
Andy Burch
EEI
SERC 5
9.
Shaun Anders
City of Springfield (CWLP)
SERC 1, 3
SERC 1, 3, 5
11. John Troha
SERC 10
2.
Group
Jonathan Hayes
X
Southwest Power Pool Standards
Development Team
Additional Member Additional Organization Region Segment Selection
3
X
SERC 1, 3, 4, 5
10. Melinda Montgomery Entergy
SERC Reliability Corp
2
X
4
5
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Jonathan Hayes
Southwest Power Pool
SPP
2
2.
Robert Rhodes
Southwest Power Pool
SPP
2
3.
Don Taylor
Westar
SPP
1, 3, 5, 6
4.
John Allen
City Utilities of Springfield
SPP
1, 4
5.
Sean Simpson
MCPBPU
SPP
1, 3, 5
6.
Louis Guidry
CLECO
SPP
1, 3, 5
7.
Mitch Williams
Western Farmers
SPP
1, 3, 5
8.
Valerie Pinnamonti
AEP
SPP
1, 3, 5
9.
Bud Averill
Grand River Dam Authority SPP
1, 3, 5
OGE
1, 3, 5
10. Terri Pyle
3.
Group
SPP
Guy Zito, Guy Zito
Additional Member
2
3
4
5
6
7
Northeast Power Coordinating Council,
Northeast Power Coordinating Council
Additional Organization
Region
Alan Adamson
New York State Reliability Council, LLC
NPCC, NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC, NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC, NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC, NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC, NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC, NPCC 2
9.
Chantel Haswell
NPCC, NPCC 10
FPL Group, Inc.
NPCC, NPCC 5
10. David Kiguel
Hydro One Networks Inc.
NPCC, NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC, NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC, NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC, NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC, NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC, NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC, NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC, NPCC 5
18. Saurabh Saksena
National Grid
NPCC, NPCC 1
19. Michael Schiavone
National Grid
NPCC, NPCC 1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
10
X
Segment Selection
1.
8
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
20. Wayne Sipperly
New York Power Authority
NPCC, NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC, NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC, NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC, NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 3
4.
Group
Emily Pennel
No additional members listed.
Southwest Power Pool Regional Entity
5.
MRO NSRF
Group
Will SMith
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Jodi Jenson
WAPA
MRO
1, 6
4.
Ken Goldsmith
ALTW
MRO
4
5.
Alice Ireland
XCEL/NSP
MRO
1, 3, 5, 6
6.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
7.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
8.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
9.
Scott Nickels
RPU
MRO
4
10. Terry Harbour
MEC
MRO
1, 3, 5, 6
11. Marie Knox
MISO
MRO
2
12. Lee Kittelson
OTP
MRO
1, 3, 4, 5
13. Scott Bos
MPW
MRO
1, 3, 5, 6
14. Tony Eddleman
NPPD
MRO
1, 3, 5
15. Mike Brytowski
GRE
MRO
1, 3, 5, 6
16. Richard Burt
MPC
MRO
1, 3, 5, 6
6.
Group
Charles W. Long
Additional Member
Additional Organization
SERC Planning Standards Subcommittee
X
X
Region Segment Selection
1. Pat Huntley
SERC
SERC
10
2. John Sullivan
Ameren Services Co.
SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Bob Jones
Southern Company Services SERC
1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Jason Adams
7.
TVA
Group
SERC
Frank Gaffney
2
3
4
5
6
7
1
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
8.
Group
FRCC
Mike Garton
Additional Member
Dominion
Additional Organization
Region Segment Selection
1. Michael Gildea
Dominion Resources Services, Inc.
RFC
2. Connie Lowe
Dominion Resources Services, Inc.
NPCC 5, 6
3. Michael Crowley
Virginia Electric and Power Company RFC
9.
Group
Annette M. Bannon
Additional Member
Additional Organization
5, 6
1, 3
PPL NERC Registered Affiliates
Region Segment Selection
1. Brent Ingebrigston
LG&E and KU Services Co.
SERC
3
2. Don Lock
PPL Brunner Island, LLC
RFC
5
3.
PPL Martins Creek, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Montour, LLC
RFC
5
6.
Lower Mount Bethel Energy, LLC RFC
5
7. Annete Bannon
PPL Susquehanna, LLC
5
8. Leland McMillan
PPL Montana, LLC
10.
Group
Jason Marshall
Additional Member
Additional Organization
RFC
WECC 5
ACES Power Marketing Standards
Collaborators
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power
RFC
2. Erin Woods
East Kentucky Power Cooperative SERC
1, 3, 5, 6
3. Michael Brytowski
Great River Energy
1, 3, 5, 6
MRO
3, 5, 6
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11.
2
3
4
5
6
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
12.
Jack Cashin
Electric Power Supply Association
X
X
Individual
14. Individual
Natalie McIntire
Tom Flynn
American Wind Energy Association
Puget Sound Energy, Inc.
X
X
X
15.
Individual
Silvia Parada Mitchell
Compliance & Responsbility Organization
16.
Individual
Southern Company
Individual
Antonio Grayson
Chris Higgins/Stephen
Enyeart/Chuck
Mathews/Charles
Sheppard
18.
Individual
Thad Ness
American Electric Power
19.
Individual
BP Wind Energy North America Inc.
Individual
Carla Bayer
John Bee on behalf of
Exelon
Individual
Dennis Sismaet
Individual
Michelle D'Antuono
Seattle City Light
Ingleside Cogeneration LP (Occidental
Chemical)
23.
Individual
Michael Falvo
Independent Electricity System Operator
24.
Individual
Greg Rowland
Duke Energy
X
25.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
26.
Individual
Kirit Shah
Ameren
27.
Individual
John Seelke
Individual
29. Individual
30.
31.
Individual
13.
17.
20.
21.
22.
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Bonneville Power Administration
X
X
X
Exelon
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PSEG
X
X
X
X
Andrew Z. Pusztai
RoLynda Shumpert
American Transmission Company
South Carolina Electric and Gas
X
X
X
X
Individual
Ravi Bantu
RES Americas Development
Individual
Katy Wilson
Sempra Generation
28.
7
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Joe Petaski
Manitoba Hydro
X
X
X
X
Individual
34. Individual
Chris de Graffenried
Ed Davis
Consolidated Edison Co. of NY, Inc.
Entergy Services
X
X
X
X
X
X
X
X
35.
Individual
Alice Ireland
Xcel Energy
X
Individual
Russell A. Noble
Cowlitz County PUD
X
X
X
36.
X
X
37.
Individual
Anthony Jablonski
ReliabiltiyFirst
X
38.
Individual
Donald Jones
Texas Reliability Entity
X
39.
Individual
Amir Hammad
Constellation Power Source Generation
40.
Individual
Dennis Chastain
Tennessee Valley Authority
32.
Individual
33.
X
X
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
X
11
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and removed the Generator Owner
from R4. Do you support the proposed redline changes to FAC-001-1? (Please refer to the posted FAC-001-1 technical
justification document for more information about the SDT’s rationale for its changes.)
Summary Consideration:
The SDT thanks all stakeholders for their comments and their 87% approval for the FAC-001-1 changes posted for ballot
in November 2011. Based on stakeholder feedback, the SDT has made the following minor changes to FAC-001-1:
-Corrected a typo in Applicability section 4.2.1 to change “within” to “with.”
-Corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather than just 3.1.1
through 3.1.6.
-Changed references to “Transmission System” to “interconnected Transmission systems” to ensure consistency with the
language elsewhere in the standard and in FAC-002-1.
Some stakeholders remain concerned about the intent of the SDT’s work on FAC-001-1. The SDT reminded them that the
scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with ownership or
operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should first address
“low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”) – that
is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
Through its deliberations, the SDT concluded that an interconnection Facility owned or operated by a GO or GOP that is
more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
Concerned commenters were also referred to one of the SDT’s resource documents: Project 2010-07: Generator
Requirements at the Transmission Interface Background Resource Document.
Some commenters suggested changes to Requirements R1 or R4, which deal exclusively with the Transmission Operator
and are outside the scope of the SDT’s work.
One commenter suggested formatting changes. The SDT agrees with the commenter that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the
standard and no change was made.
One commenter suggested that the phrase “Generator Owner’s existing Facility” be changed to “Generator Owner’s
existing Transmission Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part because in
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
12
some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC.
Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain the
term “Transmission.”
One commenter did not agree with the overall clarifying change to the Applicability section, but the SDT reminded this
commenter that this change was made to address previous comments that indicated that there was uncertainty as to
whether “another Facility to its existing generation Facility” was meant to address connecting additional generators by
the same GO. The SDT intends FAC-001-1 to apply only when the GO of an existing Facility executes an agreement to
evaluate the reliability impact of connecting additional generation owned by another GO. No change made with respect
to this comment.
A few stakeholders were concerned with the 45-day time frame included in the standard. The SDT pointed out that
majority of stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would
simply need to adopt (document and publish) the Facility connection requirements of its TO. No change to that time
frame was made.
Organization
Yes or No
Question 1 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While
the Technical Justification document states that the SDT intended to focus
on a Generator Owner’s radial interconnection facilities, the scope of the
revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
13
Organization
Yes or No
Question 1 Comment
transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis would most likely be
outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Southern Company
No
1) R4 is duplicative of R1 - either remove "maintain" from R1 or delete R4 both instances of "maintain" are not needed.  2) The measures, as
written, provide no additional indication of the evidence that could be
presented to demonstrate compliance with the Reliability Standard
Requirements. They provide little guidance on assessing non-compliance
with the Requirements.  
Response: Thank you for your comment. We agree with your suggestions, but both are outside the scope of this SDT. These items
will be submitted to the Issues Database to be addressed in a future revision of FAC-001.
Southwest Power Pool Standards
Development Team
No
Based on the applicability section of FAC-001 we feel that the strike through
should have been kept. It limited the requirement to just those generator
owners who had agreements in place, which we feel is appropriate.
Response: Thank you for your comment. This change was made to address previous comments that indicated to the SDT there was
uncertainty as to whether this was meant to address connecting additional generators by the same GO. The SDT intends FAC-001
to apply only when the GO of an existing Facility executes an agreement to evaluate the reliability impact of connecting additional
generation owned by another GO. No change made with respect to this comment.
Texas Reliability Entity
No
In Section 5.1, the reference to Regional Entity should be removed. There
are no requirements that apply to the Regional Entity.
In Requirements R1 and R4, “Planning Coordinator” should be added after
“Regional Entity.” In the ERCOT Region it is the Planning Coordinator that
maintains planning criteria and connection requirements. There is no NERC
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
14
Organization
Yes or No
Question 1 Comment
requirement or any obligation (as indicated in the technical justification
document) on the part of a GO to specifically execute an Agreement to
evaluate the reliability impact of interconnecting a third party Facility.
Therefore, this requirement’s applicability is contingent on a prerequisite
that may not occur, and that is under the control of the GO. This
assumption on the part of the SDT unnecessarily complicates the
compliance monitoring and enforcement of this standard. For instance, if
an “Agreement” is not executed, a GO is not required to comply with the
requirement, even though the GO may ultimately interconnect with another
entity. The requirement should be modified to include an applicability
trigger similar to that of FAC-002-1, so that once a GO “seek[s] to integrate .
. .,” i.e., agrees to or is compelled to allow a third-party interconnection,
then the requirement becomes applicable. Otherwise, the compliance and
monitoring is subject to the SDT’s speculation as indicated in this language
included in the technical justification document: “However, the SDT cannot
be certain this is the only example and it therefore proposes to add this new
requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a
third party to interconnect, have the necessary expertise to conduct the
required interconnect studies to meet this standard. Assuming that a
regulatory body would require a Generator Owner to evaluate such an
interconnection request, the SDT expects the Generator Owner and the
third party to execute some form of an Agreement.”
Response: Thank you for your comment. All of these comments are outside the scope of the SAR and the SDT’s work because they
refer specifically to the sections and requirements that apply to the TO alone. We encourage you to consider submitting a SAR that
addresses your concerns.
Manitoba Hydro
No
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
15
Organization
Yes or No
Question 1 Comment
While the Technical Justification document states that the SDT intended to
focus on a Generator Owner’s radial interconnection facilities, the scope of
the revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
2) If the drafting team intends to limit the scope of FAC-001-1 to GO owned
radial generator interconnection facilities that are not deemed BES
transmission and therefore would not require the registration of the GO as
a TO, Manitoba Hydro disagrees with the proposed changes to FAC-001-1 as
Generator Owners may not have the models or expertise to perform
interconnection studies to determine if there is an impact on the
Transmission Network. This concern is echoed in the technical justification
document provided by NERC: ‘the SDT acknowledges that the Generator
Owner may not, at the time it agrees or is compelled to allow a third part to
interconnect, have the necessary expertise to conduct the required
interconnect studies to meet this standard... the Generator Owner will have
to acquire such expertise. How the Generator Owner chooses to do so is
not for the SDT to determine.’ Although it may not be for the SDT to
determine how a GO obtains technical expertise, ensuring that such
expertise is acquired before a GO conducts the required interconnection
studies should be a concern to NERC as this directly affects the reliability of
the BES. As a result, all interconnection requests should be implemented by
the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User
facility as the TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If the scope
of FAC-001-1 also applies to GO owned BES transmission facilities, Manitoba
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
Hydro strongly believes that the Compliance Registry should apply and the
GOs should be required to register as a TO and abide by all applicable
standards to that functional type. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected
TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is
maintained. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively
rare.
3) If the redline changes are implemented, GOs are removed from R4,
thereby removing the obligation for GOs to maintain their connection
requirements. If GOs are included in FAC-001, they should be held
accountable to the same level as TOs and should be required to maintain
their connection requirements. Requiring a GO to maintain connection
requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would
initially be inexperienced in performing interconnection studies and would
benefit from regular and frequent review of their connection requirements
as experience and expertise are gained.
4) The revision to FAC-001-1 R2 may be problematic, depending on what
was intended. Under the revised requirement, the obligation to comply is
dependent on the execution of an agreement to evaluate reliability impacts
under FAC-002-1. However, FAC-002-1 does not clearly require the
execution of an agreement by the Generator Owner. FAC-002-1 only
requires the Generator Owner to “coordinate and cooperate on its
assessments with its Transmission Planner and Planning Authority”.
Accordingly if a Generator Owner coordinates without executing an
agreement to perform an assessment, compliance with FAC-001 R1 will not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
be required.
5) Manitoba Hydro would also like to point out that if the redline changes
are implemented, it will greatly increase the complexity of coordination
required under FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP).
The intent of the modifications to this standard is to address the requirements of the GO prior to the interconnection of the third
party to their Facilities. The reliability gap the SDT intends to close is the need for the GO to develop Facility connection
requirements prior to interconnection. The SDT does agree that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
The SDT also refers the commenter to the document titledProject 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document, which is posted on the project page. Specifically, see the last paragraph on page 4 and first two
on page 5.
Tennessee Valley Authority
No
Suggest that the overall structure of the standard be revised such that R1 R3 are applicable to the Transmission Owner (consistent with existing FAC001-0) and R4 (the new requirement) is applicable to the “applicable
Generator Owner”. See further comments below. Support the proposed
revisions to R1 and R4, but suggest R4 be returned to R3 (consistent with
existing FAC-001-0).R3 in the balloted standard should be returned to R2
(consistent with existing FAC-001-0) and only be applicable to the
Transmission Owner. R3.1 (or R2.1 if moved back) should be “fixed”, but it
may be beyond this SDT’s charge. The use of “above” in the FAC-001-0
standard, or the proposed reference to “Requirements R1 or R2” in the
proposed standard do not make sense in combination with the colon used
at the end of the requirement. Suggest that R3.1 (or 2.1 if moved back) be
revised as written below and all sub-requirements of R3.1 be elevated
(R3.1.1 becomes R3.2, R3.1.2 becomes R3.3, etc.).”R3.1 Performance
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
requirements and/or planning criteria used to assess system impacts.” R2 in
the balloted standard should become R4 and modified to incorporate the
connection requirements contained in R3 that can more reasonably be
expected of an “applicable Generator Owner”. For instance, an “applicable
Generator Owner” might simply have a connection requirement for a third
party that addresses coordination of system impact studies with the
appropriate Transmission Owner(s), in lieu of R3.1, R3.1.1, and R3.1.2.
Suggest that R2 (or R4 if moved below existing FAC-001-0 requirements) be
revised as written below.”R2 Each applicable Generator Owner that has
agreed to allow a third party Facility owner (Generation Facility,
Transmission Facility, or End-user Facility) to connect to the Transmission
system through use of pre-existing applicable Generator Owner Facilities
shall communicate it’s Facility connection requirements to the third party.
The applicable Generator Owner Facility connection requirements shall
address the following items: R2.1 Coordination of system impact studies
with the Transmission Owner. R2.2 Voltage level and MW and MVAR
capacity or demand at point of connection. R2.3 Breaker duty and surge
protection. R2.4 System protection and coordination R2.5 Metering....” Etc.
Response: Thank you for your comment. We gave the comment due consideration and agree that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the standard.
No change made.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
The intent of the draft language in FAC-001-1 is to provide guidance for
addressing the alleged reliability gap that exists between GO/GOPs that
own/ operate transmission facilities but are not registered as TO/TOPs. The
impact of the revised language will depend on the characterization of the
generator lead after the “third party “ connects to the existing generator
lead. IF the generator lead is owned by the TO utility after the third party
connection : The proposed DRAFT FAC-001 language suggests that within 45
days of a 3rd party having an executed Agreement to evaluate the reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
impact of interconnecting, the existing generator needs to document and
publish facility connection requirements. The proposed language suggests
that a third party can commandeer existing generators leads and
interconnect. A reclassification would be required because “third party”
power would flow through the downstream portions of the existing leads.
This introduces significant challenges for defining ownership / transfer of
installed assets as well as real property, easements, operational jurisdiction,
O&M cost responsibility, etc.
The FERC approved pro-forma Attachment
X Interconnection Agreement clearly states that the project Developer must
meet all Applicable Reliability Standards which means that all
requirements and guidelines of the Applicable Reliability Councils, and the
Transmission District to which the Developer’s Large Generating Facility is
directly interconnected. As an example, to accommodate this NERC
proposal, the FERC approved NYISO pro-forma tariff would need to be
revised to allow this “third party” use. The pro-forma interconnection tariff
also states that the Developer must provide updated project information
prior to the Facilities Study. The Facilities Study might not be made until
several years after the Interconnection Request /Feasibility Study is made
(“executed Agreement to evaluate the reliability impact of interconnecting”
in this proposed draft is akin to the Interconnection Request/Feasibility
Study). Placing the requirement to have the existing Generator Owner
publish reliability requirements for a potential “third party user”, without
the generator having any knowledge of the potential reliability outcomes or
asset transfer / ownership issues is not a reasonable expectation. The
interconnection of a third party to an existing generator lead would force
existing generators to revise their Interconnection Agreements with FERC.
The “third party”, would at a minimum, need to comply with the existing
Generators reliability obligations as specified in the Interconnection
Agreement.IF the third party connects to the GO owned generator lead, the
GO will be considered a TO:A TO would not be involved, other than review
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
of the SRIS and Facilities reports. The difficult thing for an existing GO
would be to prepare, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility, a document listing the requirements.
To allow for the above possibilities, the language for applicability of FAC001 to GO’s or GOP’s, should be :”Each applicable Generator Owner shall, at
least 60 days prior to execution of a Facilities / Class Year Study Agreement
to evaluate the reliability impact of interconnecting a third party Facility to
the Generator Owner’s existing Facility that is used to interconnect to the
Transmission System, document and publish its Facility connection
requirements to ensure compliance with NERC Reliability Standards and
applicable Regional Entity, sub regional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection
requirements.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Consolidated Edison Co. of NY, Inc.
No
The language for FAC-001 Requirement R2 should be:”This requirement
shall apply to each applicable Generator Owner. Generator Owner filings
must be made at least 60 days in advance of execution of the final
interconnection study agreement in the Planning Coordinator’s or
Transmission Planner’s study process.Each applicable Generation Owner
must publish its Facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Entity, sub regional,
Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.The evaluation of the reliability impact(s) of
interconnecting a third party Facility to the Generator Owner’s existing
Facility utilized for interconnection to the Transmission System must be
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
documented.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Unfortunately, the vital point of this requirement revolves around whether
or not a Generator Owner is compelled externally to allow access to their
interconnection facilities. If the GO is driving the connection for financial or
other business reasons, there is no reason they should not be responsible
for developing AND maintaining a facility connection requirements
document. Otherwise, when the local transmission system requirements
change for any reason, there will be no entity responsible to ensure that the
third party will conform as well.Conversely, if the GO should be compelled
to allow access to a third party, it is the responsibility of the “compeller” to
handle all the related reliability studies and documents. This may include
the development of a CFR which separates reliability tasks between the GO
and other entities - especially if a TSP registration is required. This ensures
that the Regional Entity, PUC, RTO, or other regulator must budget dollars
and resources directly related to their action - not cause them to be
directed to a GO.
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. However, the
issues you raise are beyond the scope of the SDT and its SAR. No change made.
PSEG
No
We revised this partial sentence to the following: “Each applicable
Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Transmission Facility that is used for connection
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
to the interconnected Transmission systems (under FAC-002-1), ...”- The
phrase “Generator Owner’s existing Facility that is used to interconnect to
the Transmission System” was changed to “Generator Owner’s existing
Transmission Facility that is used for connection to the interconnected
Transmission systems.” - “Transmission” was added before Facility to
exclude connections elsewhere; “Transmission System” was changed to
“Transmission systems” because while “Transmission” and “System” are
defined in the NERC Glossary, “System” means “A combination of
generation, transmission, and distribution components.” “Transmission
systems” do not have generation or distribution components, so a lower
case “system” is warranted. - In addition, the suggested phrase
“interconnected Transmission systems” (plural "systems") uses identical
language from FAC-002-1, except that we capitalized “Transmission.
Response: Thank you for your comment. The SDT has addressed the proposed change to applicability according to your comments.
The applicability section now reads: “Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect to the interconnected
Transmission systems.
The SDT has been informed that in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the
SDT’s attention that in most cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the
GO with FERC. Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain
the term “Transmission.”
Seattle City Light
Affirmative
Key points are that (1) an executed agreement is required before
evaluations of impacts are necessary and (2) this only applies when a third
party is connecting to the generating interconnection line.
Response: Thank you for your comment.
Electric Power Supply Association
Yes
All TO requirements for FAC-001-1 would apply if and when GO executes
an Agreement to evaluate the reliability impact of interconnecting a third
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
party Facility to its existing generation interconnection Facility. The
execution of the agreement is necessary to comply with FAC-002-1 and start
the compliance clock with the applicable regulatory authority. Thus as the
Project 2010-07 Standard Drafting Team (SDT) in its technical justification
has stated, “If, and only if, the existing owner of a generator
interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing
generation Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s
conclusion.The SDT has examined the issue regarding if future requests for
transmission service on the interconnection Facility and in doing so
acknowledged that when that Facility adopted open access and was
providing transmission service it would necessitate re-evaluation of the
need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary
agreement the SDT contemplates in its technical justification of FAC-001-1.
EPSA believes this serves as the necessary trigger for evaluation of
Requirements 2 and 4 under FAC-001-1 for GOs.
Response: Thank you for your comment.
American Wind Energy Association
Yes
AWEA appreciates that this standard specifies that it has limited
applicability. For instance, only those generators that have an executed
agreement with a third party wishing to interconnect must document and
publish Facility connection requirements. We believe the proposed 45-day
time window is a minimum for GO/GOP owners of generator lead lines to
provide this documentation following execution of such an agreement.
Anything less than 45 days could result in a burdensome and hard to meet
deadline for GO/GOP staff. However, AWEA believes that extending this
time window for publishing Facility connection requirements to 90 days
after an executed agreement would be beneficial. We believe this will allow
the GO/GOP owners of generator leads more time to coordinate with their
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
interconnecting Transmission Providers and will result in more reliable and
coordinated connection requirements for the generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO.
No change made.
SERC OC Standards Review Group
Yes
Please verify within the applicability section (4.2.1) you intended to use the
word “within” rather than some other wording.
Response: Thank you for your comment. The SDT intended it to read “Generator Owner with an executed Agreement to evaluate
the reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect
to the Transmission System.” This change has been made.
RES Americas Development
Yes
RES Americas and AWEA appreciate that this standard specifies that it has
limited applicability. For instance, only those generators that have an
executed agreement with a third party wishing to interconnect must
document and publish Facility connection requirements. We believe the
proposed 45-day time window is a minimum for GO/GOP owners of
generator lead lines to provide this documentation following execution of
such an agreement. Anything less than 45 days could result in a
burdensome and hard to meet deadline for GO/GOP staff. However, we
believes that extending this time window for publishing Facility connection
requirements to 90 days after an executed agreement would be beneficial.
We believe this will allow the GO/GOP owners of generator leads more time
to coordinate with their interconnecting Transmission Providers and will
result in more reliable and coordinated connection requirements for the
generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
Yes
We largely agree with the changes the drafting team made but believe
some additional changes are necessary. In section 4.2.1 of the Applicability
Section, “within” should be “with”. Because NERC’s Glossary of Terms
establishes that an Agreement can be verbal and not enforceable by law,
section 4.2.1 should be further modified to clarify that it is a legally
enforceable and fully executed Agreement. The language in R3 in
parenthesis after Generation Owner should be modified to “once required
by Requirement R2”. This makes it clearer that R3 does not apply until the
GO has an executed Agreement to evaluate a request by a third part to
interconnect.
No change made.
ACES Power Marketing Standards
Collaborators
Response: Thank you for your comment. We agree that “within” should be “with”. The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Southwest Power Pool Regional
Entity
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
American Electric Power
Yes
BP Wind Energy North America Inc.
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery Company LLC
Yes
Ameren
Yes
American Transmission Company
Yes
South Carolina Electric and Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 1 Comment
ReliabiltiyFirst
Entergy Services
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
27
Organization
Yes or No
Question 1 Comment
Western Electricity Coordinating
Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power Administration
Consideration of Comments: Generator Requirements at the Transmission Interface
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28
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan for FAC-001-1?
Summary Consideration:
The vast majority of commenters supported the one year compliance time frame in the Implementation Plan. A few
commenters were concerned with this time frame and associated enforcement, in part based on similar issues addressed
in recent CANs. The SDT did its best to clarify its intent as follows:
The SDT’s intent is that the mandatory date (the date upon which the GO must be compliant with applicable
requirements and measures) be the first calendar day of the first calendar quarter one year after FAC-001-1’s approval.
The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the
mandatory date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those
requirements shall address items under R3.
No changes were made to the Implementation Plan.
Organization
Yes or No
Ingleside Cogeneration LP
(Occidental Chemical)
No
Question 2 Comment
Based upon similar issues addressed in Compliance Application Notices (CANs),
the drafting team needs to specify how the requirements apply to an in-place
“executed Agreement to evaluate the reliability impact of interconnecting a
third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System.” In the view of Ingleside
Cogeneration LP, if the Agreement takes effect even one day before FAC-001-1
does, requirements R2 and R3 do not apply. Without this clarification, it is
possible that NERC’s Compliance team will apply the requirements retroactively
- with minimum industry input.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
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Organization
Yes or No
Question 2 Comment
address items under R3.
Southwest Power Pool
Regional Entity
No
No action is required unless a GO has an executed third-party agreement. If a
GO has an agreement, the standard already includes a 45-day timeframe for the
GO to document and publish its facility connection requirements.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
Southern Company
No
See our response to Question 9.
Response: See the SDT’s response to Question 9.
Manitoba Hydro
No
See question 1 comments.
Response: See SDT’s response to Question 1.
Cowlitz County PUD
Yes
Cowlitz PUD (District) registered as a Transmission Owner shortly before FAC001-0 became effective and was forced to file a Mitigation Plan in order to
facilitate compliance. The District successfully completed compliance
implementation and documentation in eight months. The proposed one year
compliance timeframe is sufficient.
Response: Thank you for your comment and support.
Seattle City Light
Yes
The proposed changes for FAC-001-1 state a 45 day period to complete the
evaluation. Not sure what the question is referring to regarding “ 1 year “?
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
American Wind Energy
Association / RES Americas
Development
Yes
Yes, since there is no exigent reason why this standard needs to be put in place
at once, we support the one-year compliance timeframe. We believe that it will
allow generators a reasonable time to comply with the requirement.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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31
Organization
Yes or No
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
PSEG
Yes
American Transmission
Company
Yes
Question 2 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
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32
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Constellation Power Source
Generation
Yes
Question 2 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
Entergy Services
ReliabiltiyFirst
Texas Reliability Entity
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
33
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the switchyard,
generating station, or generating substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the fenced area of
the generating station switchyard…” We believe that the one mile length is a reasonable approximation of line of sight, and that
using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion on
the part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this qualifier for Generator
Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are
not necessary to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will be made as
Project 2007-07—Vegetation Management moves forward, do you support the proposed redline changes to FAC-003-X and FAC003-3?
Summary Consideration:
The SDT thanks all stakeholders for their comments and their over 85% approval for the FAC-003-X and FAC-003-3
changes posted for ballot in November 2011. Based on stakeholder feedback, the SDT has made the following changes:
-Added a clarifying reference to line of sight in the GO exemption in section 4.3.1.
-Corrected a typo in 4.3.1.2 of FAC-003-3.
-Changed “RE” to “Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally
supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability
benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines
that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have
a clear line of sight from the switchyard fence to the point of interconnection and are…”
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
34
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has been agreed
upon by the stakeholder body. In its Consideration of Comments report from the last formal comment period, which
ended on July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable approximation of line of
sight, and that using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion
and any discretion on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight
reference here, the SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Some stakeholders suggested changes that should have been submitted when Project 2007-07 was revising FAC-003-2,
because these suggestions dealt with the standard as a whole rather than the changes made by this SDT to ensure that
GOs are included in the standard’s applicability.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 3 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of
said line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other
lines. If the GO is only responsible for 0.2 miles, what is the technical basis to ignore
a mile? And would it be the first mile from the switchyard that is ignored, or is the
middle mile, or the last mile where it connects to the TO? Or could the GO decide?
Or could the GO pick sections of the line that amount to a mile that they can ignore?
This seems like something that should be addressed for compliance.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
35
Organization
Yes or No
Question 3 Comment
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT chose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
Wisconsin Public Service Corp
Electric Cooperative
Negative
R1.2 refers to an encroachment due to a fall in. This is confusing because according
to the dictionary “Webster’s II” encroachment reads: “to intrude gradually”, and a
‘fall in’ is not usually gradual.
Response: Thank you for your comment. This is outside the scope of the SAR. The SDT reviewed comments submitted as part of the
Project 2007-07 effort and did not find this comment had been submitted.
Wisconsin Public Service Corp.
Negative
The concern with the proposed wording is that many generating station may not
have a “generating station switchyard” as implied by the proposed wording. Often
the generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers the
now greater than 200 kV lines will be routed to the point of interconnect or a
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
36
Organization
Yes or No
Question 3 Comment
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: A two
kilometer distance from the controlled area perimeter.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Florida Reliability
Negative
There is no technical justification for excluding 1 mile beyond the fence in the
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
37
Organization
Yes or No
Coordinating Council
Question 3 Comment
applicability of generators.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Southern Company
No
 All of these comments pertain to FAC-003-3:
1) We suggest referring to the Implementation Plan in the Effective Date sub-section
of Section A of the standard rather than repeating the content of the
Implementation Plan in the standard. There exists unnessary duplication with
including the information in both places.
2) We suggest simplifying the purpose statement to more succinctly say the intent,
for example: "To maintain a reliable transmission system by managing vegetation
located on transmission rights of way to minimize vegetation encorachments and
thereby minimize the risk of vegetation related outages". If this change is not
acceptable, at least change the phrase "preventing the risk" to "minimizing the risk".
3) We feel that the Enforcement paragraphs between 4.3.1.3 and 5.0 seem to be
out of place. Those paragraphs don’t belong in this location - consider moving them
to Section C. Compliance. The fourth paragraph belongs in the background section.
4) We suggest moving the background section to Section F. "Associated
Documents". It gets in the way of getting to the requirements of the standard.
5) We suggest moving Table 2 of the "Guideline and Technical Basis" document into
R1, since it seems to be the only part of the document that is enforceable. Further
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
38
Organization
Yes or No
Question 3 Comment
we suggest that the Guideline and Technical Basis document be removed from the
standard. The inclusion of this document in the standard makes the standard
unweildy.
6) We suggest reordering the words in R1 to more clearly state the requirement.
Please consider this rephrasing: "For lines which are either an element of an IROL or
an element of a Major WECC Transfer Path, each applicable TO and applicable GO
shall manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) when operating within their Rating during all Rated Electrical Operating
Conditions of the types shown below:..." (remainder is unchanged).
7) We suggest reordering the words of R2 to more clearly state the requirement.
Please consider the this rephrasing: "For lines which are neither an element of an
IROL nor an element of a Major WECC Transfer Path, each applicable TO and
applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within its Rating and during all Rated Electrical
Operating Conditions of the types listed below:..." (remainder is unchanged).
8) On Page 11 of the posted clean draft standard, is the reference to the previous
footnote 2 correct? We recommend eliminating footnotes where possible to
minimize redirections.
9) The Rationale text-box on page 13 of the clean version of FAC-003-3 overlaps
some of the text of footnote #6.    
Response: Thank you for your comment.
With respect to your suggestion regarding the implementation plan, the SDT simply followed the NERC-mandated document
guidelines. Making the change you suggest would deviate from that process and thus the SDT has not made it.
With respect to comments 2-8, any standard changes that go beyond making a standard applicable to a GO or GOP are beyond the
scope of this SDT. Any redline changes the SDT has made within standards were made to clarify or qualify the GO or GOP
applicability. These comments would have been more appropriate to make during the comment period for Project 2007-07
Vegetation Management, the project that revised the version of FAC-003 from which this SDT is working.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
39
Organization
Yes or No
Question 3 Comment
We have modified the rationale box on page 13 so that it does not overlap with the text of footnote 6.
Dominion
No
Dominion suggests in FAC-003-X; 4.3.1. Regional Entity be changed to RE as listed in
4.2.1 for consistency. Also Regional Entity is used throughout the rest of the
document, suggest using RE for consistency overall. Dominion suggests in FAC-003-3;
4.3.1. adding station to the following “ Overhead transmission lines that extend
greater than one mile or 1.609 kilometers beyond the fenced area of the generation
station switchyard and are” to show consistency as it is written in FAC-003-X
4.3.1.Further, Dominion is concerned that the technical justification characterized
the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard) as “approximate line of sign [sic] from a fixed point”
and notes that this line of sight may be limited by local terrain. Where line of sight of
the radial corridor is limited on a clear day due to terrain, the one mile exemption
must be limited in distance to no more than the line of sight on a clear day beyond
the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Exelon
No
FAC-003 - Exelon supports the one mile length qualifier, but feels that additional
clarification is needed to determine the points of demarcation. There are too many
differing physical configurations to use a “fence line” as a determination of
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
40
Organization
Yes or No
Question 3 Comment
applicability. Suggest that the tie line length be defined as “from the Generator Step
up Transformer GSU to the point of interconnection between the GO and TO owned
equipment.” Also suggest that the standard define what constitutes a generation
station switchyard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
Ingleside Cogeneration LP
(Occidental Chemical)
No
Ingleside Cogeneration LP is very concerned that the attempt to develop “brightline” criteria to assign applicability to either version of FAC-003 is misplaced. As seen
with NERC’s recent proposed directive related to Generator-Transmission
interconnections, those thresholds can be arbitrarily reduced based upon regulators
aversion to risk - not scientific evidence. (As it stands today, NERC has proposed any
interconnection facility operating at 100 kV or higher and greater than 3 spans in
length be applicable - which is even stricter than the TO thresholds in FAC-003.)This
would suggest that a reliability assessment consistent with the TPL standards must
be the determining factor. If the Planning Coordinator or Transmission Planner can
show that the Generator-Transmission interconnection could contribute to a
violation of an SOL or IROL, then a vegetation management program may be in
order.Furthermore, there needs to be some level of common sense applied if a GOTO interconnection is located in an area where vegetation clearance is never an
issue. A one-size-fits-all requirement based upon vegetation growth in the subtropics, should not automatically apply in the desert. In our view, every dollar spent
to control vegetation in an arid climate is one less dollar available to purchase
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
41
Organization
Yes or No
Question 3 Comment
advanced telemetry, AGC systems, and other items which have a far greater impact
on reliability.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
The SDT also took into consideration the stakeholder comments submitted and believes this exemption adequately addresses the
reliability impact for a majority of the Facilities, while balancing the efforts necessary to support the standard from all entities.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in this project. If a
Generator Owner is required to register as a TO, all the Requirements applicable to a
TO should apply. There is no need to change specific Reliability Standards to allow
the Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT also
refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface Background
Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
Suggest in FAC-003-X; 4.3.1. that Regional Entity be changed to RE as listed in 4.2.1
for consistency. Also Regional Entity is used throughout the rest of the document,
suggest using RE for consistency.In FAC-003-3; 4.3.1. add station to the following: “
Overhead transmission lines that extend greater than one mile or 1.609 kilometers
beyond the fenced area of the generation station switchyard and are” to show
consistency as it is written in FAC-003-X 4.3.1.The technical justification
characterized the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
42
Organization
Yes or No
Question 3 Comment
area of the generating station switchyard) as “approximate line of sight [sic] from a
fixed point” and noted that this line of sight may be limited by local terrain. Where
line of sight of the radial corridor is limited on a clear day due to terrain, the one mile
exemption must be limited in distance to no more than the line of sight on a clear
day beyond the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
MRO NSRF
No
The NSRF agrees with the drafting committees desire to eliminate arbitrary and
capricious behavior of auditors and industry staff by precisely defining the point at
which measurement starts for the length of transmission line. The concern the NSRF
has with the proposed wording is that many generating station may not have a
“generating station switchyard” as implied by the proposed wording. Often the
generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers
the now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
43
Organization
Yes or No
Question 3 Comment
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: NSRF
recommends a two kilometer distance from the controlled area perimeter. Our
assessment is that an individual of average height would have a line of site of
approximately 4 Kilometers. Therefore, we recommended a distance of 2 kilometers
from the Controlled Area of the plant to provide margin. The revised applicability
statement would read as follows: “Generator Owner that owns an overhead
transmission line(s) that extends greater than 2.0 kilometers beyond the Controlled
Area of the generating station up to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in
the region. Furthermore we applaud the committee for using the metric system to
identify the acceptable distance for this standard and urge it to remove all
references to English units. We strongly suggest this drafting team and all future
drafting team abandon the anachronistic English measurement system. This archaic
system, based on the length of an average barley corn, should be abandon in all
scientific and engineering endeavors.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
44
Organization
Yes or No
Question 3 Comment
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
Southwest Power Pool
Standards Development Team
No
There is a possibility of some conflict with the Bulk Electric System Definition. This
should be consistent with the Transmission Owner requirements if the lead is
determined part of the BES.
Response: Thank you for your comment. The SDT intended this standard to be applied to Facilities of GO and TO equally, with the
exception of the distance exemption for a generator interconnection Facility. The SDT also notes that FAC-003-2 (approved by the
NERC’s Board of Trustees on Nov. 3, 2011) does not rely upon the BES definition to determine the facility to which this standard
applies (200 kV or higher, or IROL or WECC Transfer Path).
South Carolina Electric and
Gas
No
There should be no qualifying exemption to FAC-003 for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
SERC Planning Standards
Subcommittee
No
We believe there should be no exemption for Generator Owners.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
45
Organization
Yes or No
Question 3 Comment
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
PSEG
No
Infigen Energy US
Affirmative
Infigen finds the DST supporting details regarding FAC-003-X to be appropriate. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
Seattle City Light
Affirmative
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
RES Americas Development /
American Wind Energy
Association
Yes
Applying the vegetation management requirements to only generator lead lines that
extend more than “one mile beyond the fenced area of the generating station
switchyard” strikes a reasonable balance among the many stakeholder positions
expressed on this topic. We think that as this criterion recognizes that there is little
need for a vegetation management plan for shorter lines, it should explicitly state
that this is true for all such facilities with lines of that length or smaller.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
46
Organization
Yes or No
Texas Reliability Entity
Yes
Question 3 Comment
In the description of the “second effective date” in FAC-003-X there is an erroneous
reference to “Requirement R3,” which should be corrected to “Requirement R1.”
Response: Thank you for your comment and support. This conforming change was made.
Seattle City Light
Yes
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
ACES Power Marketing
Standards Collaborators
Yes
We support the changes to FAC-003 suggested by the drafting team because we
believe the drafting team has provided the best solution in face of a difficult
problem. However, in general, we do not support registration of GOs and GOPs as
TOs and TOPs or applicability of any TO/TOP requirements to the GO/GOP simply
because they have a radial interconnection greater than one mile in length. While
there may be some generators that own interconnecting facilities of significant
length operated at a significant voltage that could impact BES reliability, we do not
believe that the number of generating facilities that fit into that category is
significantly large. When one considers that the majority of generators are still
owned and operator by utilities that are also registered as a TO and TOP, there is
only a minority subset of generators left that could be considered. NERC has the
registration for this remaining set of generators and could use the data to evaluate
how many of this remaining subset have interconnections owned by the generator
that are substantial enough to affect reliability. It seems that NERC could determine
the boundaries of this problem before registering anymore GOs and GOPs as TOs and
TOPs or before applying additional requirements through this effort on the GOs and
GOPs.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
47
Organization
Yes or No
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Regional Entity
Yes
Florida Municipal Power
Agency
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Question 3 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
48
Organization
Yes or No
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 3 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of
NY, Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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49
4.
Do you support compliance timeframe for Generator Owners as included and explained in the Implementation Plans for
FAC-003-X?
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-X.
One commenter found a typo in the effective dates section of FAC-003-X, where one section referenced R3 when it
should have referenced R1. That has been corrected in both the standard and the Implementation Plan.
A few stakeholders thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Beyond the corrected typo, no changes were made.
Organization
Yes or No
Ameren Services
Negative
Question 4 Comment
The 2 year compliance time line is far too long. There is significant industry evidence
that was developed in the drafting of Version 2 that supports a one year compliance
time-line for new lines. This is evidenced in Version 2. Thus there is no basis for the 2
years.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Texas Reliability Entity
No
A compliance timeframe for the applicable GOs of two years is too long and the
scenario used as a basis provides no timing specifics or details. Moreover, the 12
months for an existing transmission line operated at 200kV or higher which is newly
acquired by an asset owner and which was not previously subject to this standard is
arguably the same situation as an applicable GO but the applicable GO has an
additional 12 months to come into compliance.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so. The SDT does not believe
that a TO’s acquisition of a new asset is the same as applying new requirements to a GO.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the
drafting team needs to specify when the first vegetation management inspection
quarterly report, and any other requirement with an assigned interval in FAC-003-3 or
FAC-003-X. Even if the decision is to adopt the same criteria proposed in CAN-0012,
the industry is better served with a clear distinction made up front.
Response: Thank you for your comment. This is a comment that is outside the scope of the SDT, and in fact deals with a larger body of
standards than just FAC-003. No change made.
PSEG
No
It’s no longer applicable.
Response: Thank you for your comment. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2
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Organization
Yes or No
Question 4 Comment
– Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Manitoba Hydro
No
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southwest Power Pool
Standards Development Team
No
The effective dates should be consistent with the original standard. If there is a
reason for the extension we would like to know why.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Southern Company
Yes
The development of a working TVMP will take some time to initialize. The 1 year time
frame for R3 is appropriate. The 2 year time frame for all other requirements is
appropriate.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
Seattle City Light
Yes
The explanation deals with the fact that there are simultaneous revisions of FAC-003
underway by two different teams.
Response: Thank you for your comment and support.
MRO NSRF
Yes
There may be a typographical error on the effective date. As currently drafted the
standard states: In those jurisdictions where regulatory approval is required,
Requirement R1 applied to the Generator Owner becomes effective on the first
calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities where such explicit
approval for all requirements is required. In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption. Should it be worded
as follows? In those jurisdictions where regulatory approval is required, Requirement
R1 applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
Response: Thank you for your comment. The SDT agrees with you. “Requirement R3,” will be corrected to “Requirement R1.”
RES Americas Development/
American Wind Energy
Association
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this
standard needs to be put in place at once, we support the proposed compliance
timeframe. We believe that it will allow generators a reasonable time to comply with
the requirement.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
America Inc.
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Western Electricity
Coordinating Council
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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56
5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of different scenarios that could play out
with respect to the filing and approvals of FAC-003-2 and FAC-003-3. Do you support this approach? If there are other scenarios
that the SDT needs to account for, please suggest them here.
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-3.
One commenter thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Some stakeholders expressed confusion about the relationship between FAC-003-3 and the recently BOT-approved FAC003-2. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission
Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff
will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for
both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERCapproved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X
through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
All stakeholders should note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but
stakeholders should not vote as though they are choosing one or the other. As stated above, the SDT plans to present
FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X ready to submit to the Board if, for some
reason, neither FAC-003-2 nor FAC-003-3 are approved by FERC. Members of the ballot body should vote on the merits of
each version of FAC-003 individually. In other words, stakeholders who support adding GOs to the applicability of FAC003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Manitoba Hydro
No
Question 5 Comment
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southern Company
No
We believe that a standard development process should not have parallel paths where
the same version is being modified by multiple teams. The uncertainty in which
development path leads to confusion in the industry and ultimately proves to have
wasted come resources for the path that does not come to fruition.
Response: Thank you for your comment. While the SDT agrees this is not preferable, it was necessary given the urgency of both
projects. The SDT did the best it could to describe the scenarios and reasons for posting multiple versions.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation Management (developed under Project
2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities.
The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and
FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has
elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be
ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration agrees that the SDT’s approach is thorough. We are far more
concerned about FAC-003’s applicability criteria and implementation time frame at
this point - as stated in our responses to questions 3 and 4.
Response: Thank you for your comment and support. Please refer to the SDT’s responses to Questions 3 and 4.
ACES Power Marketing
Standards Collaborators
Yes
With recent NERC BOT approval of the FAC-003-2 standard, the drafting team should
continue to monitor the standard progress with FERC and make necessary
adjustments to the implementation plan.
Response: Thank you for your comment. The SDT acknowledges that FAC-003-2 was recently approved by the BOT. The SDT does not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
see the need to revise the GO implementation plan, as it already accounts for a number of scenarios that could occur based on how
FERC handles the filing of FAC-003-2.
Ameren
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of said
line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other lines.
If the GO is only responsible for 0.2 miles, what is the technical basis to ignore a mile?
And would it be the first mile from the switchyard that is ignored, or is the middle
mile, or the last mile where it connects to the TO? Or could the GO decide? Or could
the GO pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT choose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
PSEG
Yes
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
American Wind Energy
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
RES Americas Development
Yes
Sempra Generation
Yes
Entergy Services
Yes
Question 5 Comment
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Organization
Yes or No
Xcel Energy
Yes
Cowlitz County PUD
Yes
Texas Reliability Entity
Yes
Constellation Power Source
Generation
Yes
Tennessee Valley Authority
Yes
Question 5 Comment
Southwest Power Pool
Regional Entity
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Consideration of Comments: Generator Requirements at the Transmission Interface
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62
6. In its technical justification document, the SDT reviews all standards that had been proposed for substantive modification in the
Ad Hoc Group’s original support and explains why, with the exception of FAC-003, modifying them would not provide any
reliability benefit. Do you support these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Summary Consideration:
The SDT thanks all stakeholders for their comments.
A few commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit reference to a
generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing revisions to PRC-005-1a and
will post them soon.
Many commenters encouraged the SDT to reexamine the standards and requirements that FERC and NERC applied to
GOs and GOPs in their Milford/Cedar Creek order and draft compliance directive regarding generator leads. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider
the content of the proposed directive.
Based on stakeholder comments, the SDT expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft
compliance directive. After another thorough review of these standards, the SDT continues to believe that there are clear
and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 6 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
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Organization
Yes or No
Question 6 Comment
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Texas Reliability Entity
No
Our negative votes on FAC-003 reflect our concern that this project has not
considered all of the applicable standards. Why did the SDT choose to only review the
Ad Hoc Group’s standards when there have been multiple registration appeals in
which FERC and NERC have repeatedly cited specific additional TO/TOP standards that
were determined to be applicable to GO/GOPs? This SDT project would serve a
tremendous value to the ERO and in particular industry if it were to address the
technical aspects of the following FERC ordered applicable standards: PRC-001-1 R2,
R4; PRC-004-1 R1; TOP-004-2 R6; PER-003-1 R1; FAC-003-1 R1, R2; TOP-001-1a R1 and
FAC-004-2 R2. The SDT team should analyze the FERC orders, the applicable
standards indicated, and the circumstances and facts involved, and technically justify
why no reliability gap exists if these standards are not applied to GO interface
facilities. The SDT should include more “technical” information in its technical
justification document. For example, in regards to TOP-004-2 R7, the SDT technical
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Organization
Yes or No
Question 6 Comment
justification states that there is no reliability gap because, “. . . because an operator
has a fiduciary obligation to protect a Facility for which it is operationally
responsible.” An entity having a fiduciary obligation is not a technical justification of
why a reliability gap does not exist. Moreover, by that logic there would be no need
for many standards because every registered entity has a fiduciary obligation to
protect its facilities.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
We would like to clarify, in response to the comment concerning TOP-004-2 R7, that in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface” the SDT also stated “FAC-008-1—Facility Ratings
Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for establishing a ratings
methodology and communicating facility ratings to the Reliability Coordinator, Planning Authority, Transmission Planner, and
Transmission Operator is for use in reliable planning and operation of the Bulk Electric System.”
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
PSEG
No
PRC-005-1 - Transmission and Generation Protection System Maintenance and
Testing was recommended by the Ad Hoc Group for modification, but not addressed
to the technical justification document. It should be.
Response: Thank you for your comment. We have reviewed PRC-005-1a and believe that the wording in R1 and R2 of that standard
require the same explicit reference to a generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing
revisions to PRC-005-1a and will post them soon.
Florida Municipal Power
No
see comment to Question 7
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 6 Comment
Agency
Response: See the SDT’s response to Question 7.
Manitoba Hydro
No
See Question 7 comments.
Response: See the SDT’s response to Question 7.
MRO NSRF
No
The NSRF has one concern with the current justification and definitions. At some
point, if enough interconnections are made to generator outlet leads in accordance
with FAC-001, the original generator operator will be a Transmission Operator and a
Transmission Owner. This point in time needs to be explicitly defined by the drafting
team.
Response: The SDT cannot act on this comment. Registration is outside the scope of this SDT and resides with NERC and the Regional
Entity.
Manitoba Hydro
If the drafting team intends to limit the scope of FAC-001-1 to GO owned radial
generator interconnection facilities that are not deemed BES transmission and
therefore would not require the registration of the GO as a TO, Manitoba Hydro
disagrees with the proposed changes to FAC-001-1 as Generator Owners may not
have the models or expertise to perform interconnection studies to determine if
there is an impact on the Transmission Network. This concern is echoed in the
technical justification document provided by NERC: ‘the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third part
to interconnect, have the necessary expertise to conduct the required interconnect
studies to meet this standard... the Generator Owner will have to acquire such
expertise. How the Generator Owner chooses to do so is not for the SDT to
determine.’ Although it may not be for the SDT to determine how a GO obtains
technical expertise, ensuring that such expertise is acquired before a GO conducts the
required interconnection studies should be a concern to NERC as this directly affects
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 6 Comment
the reliability of the BES. As a result, all interconnection requests should be
implemented by the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User facility as the
TO is in the best position to set unbiased connection requirements to ensure the
reliability of the BES is maintained. If the scope of FAC-001-1 also applies to GO
owned BES transmission facilities, Manitoba Hydro strongly believes that the
Compliance Registry should apply and the GOs should be required to register as a TO
and abide by all applicable standards to that functional type. There is no need to
change specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards, including the
protection standards, are met so the reliability of the BES is maintained. At this time,
this would not lead to a large number of extra registrations since, as stated in the
technical justification document, ‘interconnection requests for Generator Owner
Facilities are still relatively rare.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs. The SDT does agree that upon interconnection of a third party, other standards or registrations
may apply as appropriate.
Electric Power Supply
Association
Affirmative
All TO requirements for FAC-001-1 would apply if and when GO executes an
Agreement to evaluate the reliability impact of interconnecting a third party Facility
to its existing generation interconnection Facility. The execution of the agreement is
necessary to comply with FAC-002-1 and start the compliance clock with the
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Question 6 Comment
applicable regulatory authority. Thus as the Project 2010-07 Standard Drafting Team
(SDT) in its technical justification has stated, “If, and only if, the existing owner of a
generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation
Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s conclusion. The SDT
has examined the issue regarding if future requests for transmission service on the
interconnection Facility and in doing so acknowledged that when that Facility adopted
open access and was providing transmission service it would necessitate re-evaluation
of the need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary agreement
the SDT contemplates in its technical justification of FAC-001-1. EPSA believes this
serves as the necessary trigger for evaluation of Requirements 2 and 4 under FAC001-1 for GOs.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen supports the FAC-001-1 technical analysis by the Project 2010-07 SDT, which
states in part that “If, and only if, the existing owner of a generator interconnection
Facility has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply”. We agree with the SDT’s reasoning that if the owner of
the existing generator interconnection Facility agrees, or is compelled to allow a third
party to interconnect, but can do so using existing agreements, contracts, and/or
tariffs [to avoid requiring additional executed Agreement(s)], this is the most prudent
and effective way to manage this process with continuity. In order to evaluate the
reliability impact of interconnecting a third party Facility to the Generator Owner’s
existing Facility more expediently, it can avoid having to develop its own connection
requirements or perform additional impact studies, to the extent possible. We find it
reasonable to negotiate with the existing Transmission Owner, Transmission Planner,
and/or Transmission Service Provider to manage this requirement, utilizing their
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Question 6 Comment
existing processes and Agreements for the purpose of fulfilling FAC-001-1.
Response: Thank you for your comment and support.
Southern Company
Yes
Additional responses are needed to justify the exclusion of the list of requirements
and standards found in the recent FERC order denying the rehearing request of the
Compliance Registry Appeals of Cedar Creek and Milford. (135 FERC Para. 61,241).
Please see our response to Question 10 for a detailed discussion on this
topic.   
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
Constellation Power Source
Generation
Yes
Constellation supports the SDT justifications and offers additional information in our
response to question 10.
Response: Thank you for your comment and support.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration LP believes the SDT has spent a significant amount of time and
effort to demonstrate that only FAC-001, FAC-003, and PRC-004 need to be modified
to address any reliability gaps that may exist related to the GO-TO interconnection.
We agree that the other standards/requirements identified by the Ad Hoc Group are
covered elsewhere.
Response: Thank you for your comment and support.
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Organization
Yes or No
American Wind Energy
Association
Yes
Question 6 Comment
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
RES Americas Development
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
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Organization
Yes or No
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Yes
Question 6 Comment
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Organization
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Question 6 Comment
Gas
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Independent Electricity
System Operator
Ameren
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
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Question 6 Comment
Tennessee Valley Authority
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7. The SDT is attempting to modify a set of standards so that radial generator interconnection Facilities are appropriately accounted
for in NERC’s Reliability Standards, both to close reliability gaps and to prevent the unnecessary registration of GOs and GOPs at
TOs and TOPs. Does the set of standards currently posted achieve this goal?
Summary Consideration:
The SDT thanks all stakeholders for their comments. Most commenters support the SDT’s work and agree that the set of
standards for which the SDT has proposed modification ensure that radial generator interconnection Facilities are
appropriately accounted for in NERC’s Reliability Standards.
One commenter continues to express confusion about the scope of the SDT’s work in general. The SDT reminded this
commenter that its scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with
ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it
should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
transmission entity (TO/TOP). Through its deliberations, the SDT came to the conclusion that an interconnection Facility
owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT. The SDT also refers the commenter to the document titled Project
2010-07: Generator Requirements at the Transmission Interface Background Resource Document (specifically, the last
paragraph on page 4 and first two on page 5). The SDT has proposed the modification of a select set of standards so that
they apply to GOs and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been
widely supported by the stakeholder body. The SDT does agree that upon interconnection of a third party, other
standards or registrations may apply as appropriate.
One commenter asked the SDT to specify what it means by “radial.” By “radial generator interconnection Facilities,” the
SDT means sole-use Facilities (see posted examples under “Supporting Materials”) – that is, a Facility used to connect one
or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
A few commenters suggested that the SDT address those standards cited by FERC and NERC in related projects. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process. However, based on staekolder
comments, the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include
any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
After another thorough review of these standards, the SDT continues to believe that there are clear and technical
reliability-based reasons that support not adding GO and GOP requirements to these standards.
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One commenter suggested that the SDT include the GO in TOP-004-2 R6, but the SDT continues to maintain that no gap
exists because TOP-002-2 R3 already requires the GO to coordinate with its host BA and TSP, who in turn are required to
coordinate with their TOPs.
One commenter pointed out that the Data Retention section of the proposed PRC-004-2.1a also requires modification to
include the generator interconnection Facility. The SDT agrees and made this change.
Organization
Yes or No
Manitoba Hydro
Negative
Question 7 Comment
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
2) Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry
and only having a limited set of standards apply to the GOs ‘interconnection facilities’
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
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“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Manitoba Hydro
Negative
Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry and
only having a limited set of standards apply to the GOs ‘interconnection facilities’ If a
Generator Owner wants to own transmission facilities and it falls under the definition
of a Transmission Owner under the NERC Registry Criteria, then all the Requirements
applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions.
Reliability gaps would be better closed if select GOs and GOPs simply registered as
TOs and TOPs. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document, ‘interconnection
requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The SDT has proposed the modification of a select set of standards so that they apply to GOs
and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the
stakeholder body. The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as
appropriate.
PSEG
No
It would be helpful if the SDT defined what it means by the term “radial generator
interconnection Facilities.” Does it mean interconnection Facilities that under Normal
Clearing for a fault do not interrupt flows on other BES Elements? This is also
confusing because of the radial exclusion included in the BES definition work in
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Project 2010-17. That definition would allow part of a three-terminal circuit to be
excluded from the BES, while the other parts are included in the BES.
Response: Thank you for your comment. By “radial generator interconnection Facilities,” the SDT means sole-use Facilities (see posted
examples under “Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated
by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that a interconnection Facility owned or
operated by a GO/GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside
the scope of this SDT.
Texas Reliability Entity
No
See comment 6.
Response: See the SDT’s response to Question 6.
Manitoba Hydro
No
The SDT’s proposed modifications gives special treatment to the Generator Owner in
that it allows the Generator Owner TO status for a couple of standards (FAC-001, FAC003 and PRC-004), but exempts the Generator Owner from many of the standards
applicable to a TO. The NERC Registry Criteria defines the various functional entities.
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
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GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Southwest Power Pool
Regional Entity
No
The Technical Justification document did not review the standards FERC identified in
paragraphs 71 and 87 of 135 FERC ¶ 61,241 ORDER DENYING APPEALS OF ELECTRIC
RELIABILITY ORGANIZATION REGISTRATION DETERMINATIONS. The SDT needs to
review these standards to determine if changes are needed; otherwise, FERC will
require registration of GOs and GOPs as TOs and TOPs to address reliability gaps. If
the SDT determines no changes are needed to these FERC-identified standards, they
should provide justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives) within the standards process. However, based on your and other comments, we have
expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards,
the SDT continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP
requirements to these standards.
Southern Company
No
We don’t believe the effort realizes the goal because 1) it is inclusive of FAC-001 that
does not need any modifications and 2) the effort needs to reinforce the appropriate
justification not to include the additional standards FERC has identified in their Cedar
Creek and Milford Orders.
Response: The SDT thanks you for your comment. The SDT believes that comment (1) is a complex issue and did its best to outline
how it arrived at its position in the document titled “Technical Justification: FAC-001-1.”
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As for comment (2), the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that don’t
include explicit directives) within the standards process. However, based on your and other comments, we have expanded our
technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
Western Electricity
Coordinating Council
No
WECC casts an affirmative vote for the SDT proposal as a necessary but not sufficient
step in addressing the GOTO matter. WECC, NERC, and the other Regions developed
a subset of Standards and Requirements that were considered necessary to address
potential gaps for transmission interconnection facilities and operations to be
included in a proposed NERC Directive, which is expected to issue by year-end. The
subset of requirements developed for the proposed NERC Directive were informed by
the applicable FERC Orders. Consequently, it is important that the SDT address the
comparative reliability risks between the proposed NERC Directive List and the SDT
Proposal to assure that reliability gaps will not result from the SDT proposal. Please
see NERC’s proposed Directive for the rationale and technical justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
However, based on your and other comments, we have expanded our technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance
directive. After another thorough review of these standards, the SDT continues to believe that there are clear and technical reliabilitybased reasons that support not adding GO and GOP requirements to these standards.
Florida Municipal Power
Agency
FMPA believes that TOP-004-2 R6.2 ought to also be addressed in the standards as
applicable to GOPs. The requirements reads:R6. Transmission Operators, individually
and jointly with other Transmission Operators, shall develop, maintain, and
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implement formal policies and procedures to provide for transmission reliability.
These policies and procedures shall address the execution and coordination of
activities that impact inter- and intra-Regional reliability, including:R6.2. Switching
transmission elements.Although planned outages are covered in other standards
applicable to a GOP, switching to close / synchronize a generator back to the system is
not specifically covered in the standards. Some have argued that TOP-002-2 R3 causes
GOPs to coordinate its current day plans with the TOP; however, the name of the
standard is “Transmission Operations Planning” and therefore implies the availability
of the generator and related equipment and not necessary implies the policies and
procedures for switching operations; which includes synchronization. FMPA cannot
imagine a generator that would not have such switching / synchronization policies
and procedures coordinated with its interconnecting TOP; as such would normally be
required through a Large Generator Interconnection Agreement through a pro forma
OATT; however, FMPA is not aware of any instance in the standards that covers this.
As such, FMPA recommends including TOP-004-2 R6.2 as being applicable to a GOP.
Response: Thank you for your comment. We don’t agree that the gap exists because TOP-002-2 R3 already requires the GO to
coordinate with its host BA and TSP, who in turn are required to coordinate with their TOPs.
Manitoba Hydro
If the redline changes are implemented, GOs are removed from R4, thereby removing
the obligation for GOs to maintain their connection requirements. If GOs are included
in FAC-001, they should be held accountable to the same level as TOs and should be
required to maintain their connection requirements. Requiring a GO to maintain
connection requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would initially
be inexperienced in performing interconnection studies and would benefit from
regular and frequent review of their connection requirements as experience and
expertise are gained.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
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Question 7 Comment
in the document titled “Technical Justification: FAC-001-1.”
SERC OC Standards Review
Group
Please list the set of standards are you referencing.
Response: The SDT is referring to those standards posted for comment (FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1).
Constellation Power Source
Generation, Inc.
Affirmative
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. Please see more detailed comments submitted in the Project 201007 comment form submitted on November 18, 2011.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen finds the SDT supporting measures and analysis regarding FAC-003-3 to be
appropriate, and believes that it is prudent for Generation Owners and Transmission
Owners to manage vegetation maintenance records/inspections accordingly. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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Question 7 Comment
significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
Affirmative
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
The SDT agrees with your comment regarding the language in the Data Retention section and has modified that section as follows:
“The Transmission Owner, and Distribution Provider that own a transmission Protection System and the Generator Owner that owns a
generation or generator interconnection Protection System…”
Southwest Transmission
Cooperative, Inc. / ACES
Power Marketing
Affirmative
We largely support the changes made by drafting team because we believe the
drafting team has provided the best solution in face of a difficult problem. However,
in general, we do not support registration of GOs and GOPs as TOs and TOPs or
applicability of any TO/TOP requirements to the GO/GOP simply because they have a
radial interconnection greater than one mile in length. While there may be some
generators that own interconnecting facilities of significant length operated at a
significant voltage that could impact BES reliability, we do not believe that the
number of generating facilities that fit into that category is significantly large. When
one considers that the majority of generators are still owned and operator by utilities
that are also registered as a TO and TOP, there is only a minority subset of generators
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left that could be considered. NERC has the registration for this remaining set of
generators and could use the data to evaluate how many of this remaining subset
have interconnections owned by the generator that are substantial enough to affect
reliability. It seems that NERC could determine the boundaries of this problem before
registering anymore GOs and GOPs as TOs and TOPs or before applying additional
requirements through this effort on the GOs and GOPs. Subjecting a GO/GOP to any
TO/TOP standards requirements should require a clear demonstration f the reliability
gap in each instance. Some additional changes are necessary to FAC-001.
Response: Thank you for your comment and support. We are unsure as to what changes to FAC-001 you feel are necessary unless you
are referring to comments stated previously.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Although the SDT is nearing conclusion on the closing of reliability gaps, the
unnecessary registration of GOs and GOPs as TOs and TOPs is far from resolved in our
view. Ingleside Cogeneration’s concern is based upon NERC’s recent proposal to
dictate an interim GO-TO interconnection solution which completely bypasses the
Standards Development Process. Frankly, it seriously brings to question the nature of
the consensus-driven process - which appears to be moving in a dictatorial direction.
Response: Thank you for your comment and support.
American Wind Energy
Association
Yes
AWEA believes that the standards modifications proposed by the SDT should address
any genuine reliability gap with regard to generator lead lines, rather than just
perceived but unsupported threats. To that end, we support the approach that the
SDT appears to be taking of modifying a limited number of applicable standards so
that they apply to GO/GOP lead lines. In particular, we fully support the fact that the
SDT recognizes that GO/GOPs should not automatically be required to register as
TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case
determination. As already noted, registering a GO/GOP as a TO/TOP may actually
decrease reliability.
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Question 7 Comment
Response: Thank you for your comment and support.
RES Americas Development
Yes
We believe that the standards modifications proposed by the SDT should address any
genuine reliability gap with regard to generator lead lines, rather than just perceived
but unsupported threats. To that end, we support the approach that the SDT appears
to be taking of modifying a limited number of applicable standards so that they apply
to GO/GOP lead lines. In particular, we fully support the fact that the SDT recognizes
that GO/GOPs should not automatically be required to register as TO/TOPs simply
because of their ownership of generator lead lines. The SDT correctly recognizes that
such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Response: Thank you for your comment and support.
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Yes
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Organization
Yes or No
Question 7 Comment
Standards Collaborators
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Xcel Energy
Yes
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Organization
Yes or No
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 7 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
South Carolina Electric and
Gas
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
Tennessee Valley Authority
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8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the appropriate ones?
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, commenters either offered their support or directed
the SDT to their comments on other questions in this report.
Organization
Yes or No
Ameren
No
Question 8 Comment
Please refre to our comments in reposnes to #3, #4, and #5 above.
Response: Please see the SDT’s responses to Questions 3, 4, and 5.
Texas Reliability Entity
No
See comment 6.
Response: Please see the SDT’s response to Question 6.
Ingleside Cogeneration LP
(Occidental Chemical)
No
See comments to questions 1 through 4.
Response: Please see the SDT’s responses to Questions 1-4.
SERC Planning Standards
Subcommittee
No
See our comments above for question # 3.
Response: Please see the SDT’s response to Question 3.
South Carolina Electric and
Gas
No
The modifications are appropriate with the exception noted in question #3.
Response: Please see the SDT’s response to Question 3.
ACES Power Marketing
No
The modifications are largely the appropriate ones with the exceptions we noted in Q1
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Organization
Yes or No
Standards Collaborators
Question 8 Comment
and Q10.
Response: Please see the SDT’s responses to Questions 1 and 10.
Southwest Power Pool
Standards Development Team
No
We agree that the standards being addressed are correct. See above comments.
There are some issues with the determination of which facilities are deemed BES since
ownership of what may be a BES facility may not always be by a Transmission Owner.
All relevant standards should apply to BES facilities regardless of ownership.
Response: Thank you for your comment.
PSEG
No
Response:
SERC OC Standards Review
Group
See comments on Question 7. If the standards referenced in question 7 are FAC-001,
FAC-003 and PRC-004, we would answer yes to this question.
Response: Thank you for your comment and support.
Southern Company
Yes
 The version history table is incorrect - change version 3 to version 2.1.  
Response: Thank you for your comment. We have made this change.
RES Americas Development/
American Wind Energy
Association
Yes
For the most, we agree that the SDT proposal strikes a reasonable balance and
provides the requisite level of clarity and certainty necessary for GO/GOPs to
understand their responsibilities and compliance requirements.
Response: Thank you for your comment and support.
MRO NSRF
Yes
The NSRF agrees if the drafting team incorporates as suggested improvements
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Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment and support.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Yes
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Organization
Yes or No
Question 8 Comment
Company
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
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9. If you answered “no” to Question 7, what standards need to be added or removed to achieve the SDT’s goal? Please provide
technical justification for your answer.
Summary Consideration:
The SDT thanks all stakeholders who submitted comments. Few stakeholders suggested that standards need to be added
or removed to achieve the SDT’s goal.
One commenter pointed out that PRC-005-1a required the same kind of change made in the proposed PRC-004-2.1a to
ensure that generator interconnection Facility Protection Systems are included within that standard. The SDT agrees with
this suggestion and has initiated a process to modify R1 and R2 in PRC-005-1a.
A few commenters returned to FAC-001-1 and stated their concern about the feasibility of adding FAC-001-1 to the
applicability section of this standard. The SDT agrees with commenters that the issues surrounding the interconnection of
a third party Facility to a GO’s existing Facilities are complex ones, and reminded commenters that it did its best to
address these complexities in the resource document titled “Technical Justification: FAC-001-1.” The SDT also points out
that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or indirectly
with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro
forma interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any
studies with an affected system which could include Facilities owned by one, or more, TO on the other side of the GO’s
existing point of interconnection. The SDT acknowledges that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
Some commenters suggested that the SDT reexamine the standards cited in the Milford and Cedar Creek FERC orders.
The SDT continues to find clear and technical reliability-based reasons that support not adding GO and GOP requirements
to these standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern,
the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 9 Comment
Cowlitz County PUD
No
N/A
Manitoba Hydro
No
See question 7 comments.
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Organization
Yes or No
Question 9 Comment
Response: See the SDT’s response to Question 7.
Southern Company
Yes
Southern does not think that the revision to FAC-001-1 is necessary. A Generator
Owner (GO) cannot assess reliability impacts to the Bulk Electric System (BES) and
determine acceptability without support and involvement of the applicable owner and
operator of the Transmission System (i.e., the “interconnected TO” or “interconnected
TP”). A generator tie-line does not equate to a Transmission System. A GO must
already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties’ facilities to its own interconnection
Facilities. Stated another way, the GO does not need Facility Connection
requirements to govern how multiple units are tied to a collector bus so why are they
needed for a third party to connect to an existing tie-line? In either case it is the
interconnected TO or interconnected TP that has connection requirements that must
be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its
interconnected TO or interconnected TP. A GO should not need to develop
“connection requirements” unless it is in the business of owning and operating
facilities independently of its interconnected TO or interconnected TP. We do not
believe a reliability gap exists in FAC-001-1 because the requestor for interconnecting
another Facility to an existing generation Facility must coordinate with the applicable
TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable facility
connection and performance requirements. If and when there is an agreement in
place for a third party to connect to a generator tie-line then the tie-line would
become part of the integrated system and its purpose and the owner’s function would
likely warrant registration as a TO/TOP and FAC-001 would then apply. The following
excerpt from the 2010-07 Background Resource White Paper acknowledges that this
may be necessary: “The drafting team also acknowledges that, if another party
interconnects to a Facility owned by a Generator Owner, there may be the need to
address MOD or TPL standards. However, the drafting team believes that this, too, is
best handled through specific evaluation, perhaps accompanied by changes to the
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Organization
Yes or No
Question 9 Comment
compliance registry. Entities that face this kind of scenario may also meet criteria
applicable to other registrations such as Transmission Service Provider or Transmission
Planner.” [Arguments related to jurisdictional, interconnection policy and open access
transmission tariff issues](1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access
transmission tariff (OATT), a GO should not be required to comply with FAC-001-1
until that GO’s generating Facility reaches commercial operation. NERC should not
make facilities subject to the mandatory reliability standards before the facilities are
actually part of the BES.(a) Jurisdiction under FPA Section 215. First, it is not clear
that NERC or FERC has jurisdiction under FPA Section 215 to require generation
facilities that have not actually reached commercial operation to be subject to
reliability standards. Section 215(a)(2) of the FPA defines the “Electric Reliability
Organization” as “the organization certified by the Commission ... the purpose of
which is to establish and enforce reliability standards for the bulk-power system,
subject to Commission review.” Further, (a)(3) provides that “The term ‘reliability
standard’ means a requirement, approved by the Commission under this section, to
provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide
for reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design
of planned additions or modifications. It is logical to interpret the phrase “design of
new facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted
as requiring that a generating facility that has not yet reached commercial operation
should be subject to reliability standards (including audit and penalties). Therefore,
the GO with the existing generation facilities should not be required to incorporate
the proposed generation facility into its Facility connection requirements before the
proposed generation facility is subject to NERC or FERC jurisdiction. (b) FERC’s
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Organization
Yes or No
Question 9 Comment
interconnection policy. In addition, the revised FAC-001 would appear to place
restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC
was very concerned about the ability of interconnection customers to interconnect
their generating facilities and gave them a fair amount of flexibility. However, this
revised FAC-001 would appear to restrict some of this flexibility.(i) Order No. 2003
gives the interconnection customer the ability to terminate a proposed
interconnection on ninety days notice. Therefore, the interconnection customer is not
required to build the facility. However, this revised FAC-001 appears to assume that
the interconnection customer does not have this flexibility. What if the
interconnection customer (the GO building a new generator on its site or the third
party building a new generation facility) decides to terminate the Large Generator
Interconnection Agreement (LGIA) or not proceed with the generation facility? In such
event, the GO may be required to revert to its previous Facility connection
requirements in order to accommodate the original configuration. (ii) The LGIA
permits modifications to the proposed interconnection. How would this affect the
Facility connection requirements? How long would the GO have to revise its Facility
connection requirements? In the event that there is a single modification, or perhaps
multiple modifications, how does the GO stay in compliance with this standard? (iii)
FAC-001-1, R4 provides that each GO with Facility connection requirements and each
TO shall maintain Facility connection requirements and make documentation of these
requirements available to users of the Transmission System upon request. However,
Large Generator Interconnection Procedures (LGIP), Section 3.4 requires the posting
of certain interconnection information but the identity of the interconnection
customer is not to be disclosed (unless it is an Affiliate). Requirement R4 would
appear to potentially require disclosure of information and (more importantly) of the
interconnection customer's identity in contravention of the requirements in Order No.
2003 and the LGIP.(c) OATT requirements. The definition of “applicable Generator
Owner” (Section 4.2.1) and Requirement R2 provide that the GO will have an executed
Agreement to evaluate the impact of interconnecting a new facility to the GO’s
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Organization
Yes or No
Question 9 Comment
existing generation facility. This statement is ambiguous. This statement could be
understood to mean that the GO of the existing generation Facility will enter into an
Agreement with the GO proposing to interconnect and the existing GO will evaluate
the impact of the proposed interconnection. However, requests to interconnect new
generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the
new facility. Thus, the language in FAC-001-1 would need to be revised to clarify that
the owner of the new facility will need to interconnect under the OATT of an
appropriate Transmission Provider (i.e., the Transmission Provider to which the
existing GO is interconnected, not with the existing GO). Therefore, the owner of the
new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be
developing a merchant transmission line. In that case, the existing GO would need to
evaluate whether it needs have its own OATT and OASIS. In that case, the new
generator owner would be interconnecting to the existing GO. However, the existing
GO’s line would not be a generator tie-line. This issue is not clear from the draft
standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES
reliability...” (b) It is unclear in Applicability section 4.2.1 that the term “Agreement”
means that the GO has an executed agreement with a TO/TSP or that the GO and the
third party have an executed agreement. Without further explanation, the capitalized
term “Agreement” has the effect of introducing confusion. If the SDT does not intend
to propose a new addition to the NERC Glossary of Terms, it should use the lower case
term, “agreement.” With respect to the capitalized term, “Transmission System,” the
SDT should consider clarifying if it intends to propose adding this to the Glossary. (3)
Effect of the proposed revisions to FAC-001-1 on FAC-002-1.(a) As drafted, there are
scenarios under which a new GO may attempt to interconnect to an existing GO even
though, as explained above, the interconnection should actually be done to the
appropriate Transmission Provider. If the appropriate Transmission Provider is not
included in the evaluation of the interconnection various types of harm may occur. In
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Organization
Yes or No
Question 9 Comment
such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002. (b) FAC-001 and FAC-002 should
be revised to be clear that the existing GO and any new GOs must coordinate any
interconnection with the appropriate Transmission Provider, TP and PA.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as appropriate.
PSEG
Yes
We believe that the Ad Hoc Group’s suggestions regarding PRC-005-1 - Transmission
and Generation Protection System Maintenance were correct and that this standard
should have been modified by the SDT in a manner similar to the way the SDT
modified PRC-004-2. This would require modifying R1 and R2 in PRC-005-1a (the
current version) to include protection systems in the generator interconnection
Facility. In addition, the SDT should evaluate modifying PER-002-0 - Operation
Personnel Training. In doing so the SDT completes one of the open FERC directives in
Order 693. Paragraph 1363 addresses GOP training:1363. Further, the Commission
agrees with MidAmerican, SDG&E and others that the experience and knowledge
required by transmission operators about Bulk-Power System operations goes well
beyond what is needed by generation operators; therefore, training for generator
operators need not be as extensive as that required for transmission operators.
Accordingly, the training requirements developed by the ERO should be tailored in
their scope, content and duration so as to be appropriate to generation operations
personnel and the objective of promoting system reliability. Thus, in addition to
modifying the Reliability Standard to identify generator operators as applicable
entities, we direct the ERO to develop specific Requirements addressing the scope,
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Organization
Yes or No
Question 9 Comment
content and duration appropriate for generator operator personnel.
Response: Thank you for your comment. The SDT agrees with the comment concerning PRC-005-1a and will be initiating a process to
make that change.
With respect to PER-002-0, the SDT continues to find that there are no clear and technical reliability reasons that support adding GOP
requirements to any PER standard based on the fact that the GOP operates a generator interconnection Facility. While the SDT does
not necessarily disagree that some training requirements for GOPs may be necessary, it does not see how these changes fall within its
scope.
Ingleside Cogeneration LP
(Occidental Chemical)
Ingleside Cogeneration LP believes that the set of standards proposed by the SDT is
technologically accurate and defensible. The open issue is if the ERO and FERC expect
more standards to be included - whether based upon sound reliability principals or
not.
Response: Thank you for your comment and support.
Western Electricity
Coordinating Council
PLease see response to question #7.
Response: See the SDT’s response to Question 7.
Texas Reliability Entity
See comment 6.
Response: See the SDT’s response to Question 6.
SERC OC Standards Review
Group
See comments on Questions 7 & 8.
Response: See the SDT’s responses to Questions 7 and 8.
Florida Municipal Power
see response to Question 7
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Organization
Yes or No
Question 9 Comment
Agency
Response: See the SDT’s response to Questions 7.
Manitoba Hydro
The revision to FAC-001-1 R2 may be problematic, depending on what was intended.
Under the revised requirement, the obligation to comply is dependent on the
execution of an agreement to evaluate reliability impacts under FAC-002-1. However,
FAC-002-1 does not clearly require the execution of an agreement by the Generator
Owner. FAC-002-1 only requires the Generator Owner to “coordinate and cooperate
on its assessments with its Transmission Planner and Planning Authority”. Accordingly
if a Generator Owner coordinates without executing an agreement to perform an
assessment, compliance with FAC-001 R1 will not be required.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Southwest Power Pool
Regional Entity
The SDT should consider the standards that FERC identified in 135 FERC ¶ 61,241.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives). However, based on your and other comments, we have expanded our technical
justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
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10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, many stakeholders offered supportive comments.
Others offered a variety of suggestions, many of which were addressed.
One commenter suggested that the word “system” should not be capitalized in “Transmission System” in FAC-001-1
because the NERC glossary term “System” does not apply within the standard. The SDT agreed with this suggestion, and
changed all references to “Transmission System” to “interconnected Transmission systems” for consistency in other parts
of the standard and with FAC-002. Another commenter pointed out that “within” should be “with” in Section 4.2.1, and
the SDT made this change.
A few commenters repeated their concern with the exclusion in FAC-003 for GOs with specific kinds of interconnection
Facilities. For these commenters, the SDT reemphasized that in many cases, generation Facilities are either (1) staffed and
the overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have
generally supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines
that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have
a clear line of sight from the switchyard fence to the point of interconnection and are…”
Some stakeholders offered comments that were outside the scope of this SDT’s work. A few offered comments on the
overall strategy of the FAC-003-2 standard, and the SDT informed them that these comments should have been
submitted when the Project 2007-7 Vegetation Management posted its work for comment.
One commenter suggested changes to the VSLs for R1 and R4. Because the SDT made no changes to these requirements,
modifying the VSLs for these requirements is outside the scope of this team. This item will be added to the issues
database.
Several stakeholders suggested the SDT review the standards cited in the draft NERC directive regarding generator
interconnection leads and in the FERC orders regarding Milford and Cedar Creek. The SDT continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these standards and not
requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern, the SDT has expanded its
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technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 10 Comment
Gainesville Regional Utilities
Negative
1. It would seem that the impetus for FAC003 is to eliminate vegetation related
outages within the rights-of-way as defined and subject to the exclusions as stated in
footnote
2. Thus the requirement is to manage the ROW to prevent vegetation related
sustained outages with the measure being no outages. With grow-ins and fall-ins from
within the defined ROW being controllable factors. 2. Including encroachments leaves
the door open for fines to be imposed with no actual outage(s) having occurred. This
may be like being found guilty of a crime that has not yet taken place.
3. Combine vegetation related sustained outages by “grow-ins” and “blowing
together of lines and vegetation located inside the ROW” as one item as they are both
consequences of the growth of vegetation either vertically and horizontally.
4. Leave vegetation related sustained outages by “fall-in” as a standalone as this will
be related to structural problems occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and implementation of a Transmission
Vegetation Management Plan which shall include documented maintenance
strategies or procedures or processes or specifications, delineation of an annual work
plan and completion of same). Thus this would be the competency based
requirements as a program without execution is meaningless.
6. R1 and R2 become R2 and R3.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and found that a response to this comment was provided. No change made.
Northern Indiana Public
Service Co.
Negative
Ballot needs work
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0
Organization
Yes or No
Question 10 Comment
Response: The SDT does not understand your specific concern.
PSEG Energy Resources &
Trade LLC, PSEG Fossil LLC,
Public Service Electric and Gas
Co.
Negative
FAC-003-X is not applicable since FAC-003-2 was approved by the BOT on November
4, 2011
Response: Thank you for your comment. You are correct that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 –
Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Hydro-Quebec TransEnergie
Negative
Hydro-Quebec TransEnergie is casting a negative vote again because our comment
from the last posting was not considered in the current draft: The minimum
frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of 50 degrees
North, the vegetation growth rates is limited. The Vegetation Inspection frequency in
the territories located above 50 degrees of latitude must be relaxed to 3 years.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and did not find this comment had been submitted as part of that project effort. No
changes made.
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1
Organization
Yes or No
Question 10 Comment
New Brunswick System
Operator
Negative
Since NBSO voted 'affirmative' for FAC-003-3, it makes sense for us to vote 'negative'
for this standard.
Response: Thank you for your comment. In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with
the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually
only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved
by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation
on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
PSEG Energy Resources &
Trade LLC/ Public Service
Electric and Gas Co./ PSEG
Fossil LLC
Negative
The phrase “generator Facility” should be “generator Transmission Facility,” and the
phrase “Transmission System” should be “Transmission system.”
Response: Thank you for your comment. We agree with your change to “Transmission system” but not to the addition of
“Transmission” in the phrase “generator Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part
because in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC. Therefore, the SDT
intentionally modified language so that a Facility owned by a generation entity did not contain the term “Transmission.”
SERC Reliability Corporation
Negative
There should not be a weak link under the standard. This proposed revision would
create a weak-link where a portion of the otherwise covered right-of-way would be
exposed.
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Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
New York State Department
of Public Service/ National
Association of Regulatory
Utility Commissioners
Negative
Understand that there is an open issue regarding the availablility of generation
compliance documentation that needs to be satisfactorily addressed.
Response: The SDT does not understand your specific concern.
Infigen Energy US
Affirmative
Infigen supports the efforts of the SDT to ensure that Protection System
Misoperations affecting the reliability of the BES are thoroughly analyzed and
mitigated. Generator Owners are already analyzing Misoperations as/if they occur,
and are employing Corrective Action Plans to avoid future Misoperations. We support
maintaining "reasonable and appropriate" preventative measures and risk assessment
tools to ensure that misoperations are evaluated and corrected expediently.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC/PPL NERC
Registered Affiliates
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
SERC Reliability Corporation
Affirmative
The Generator Owner may be required to self-certify and report periodically to the
region whether they have become applicable to the standard.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc./ ACES Power
Marketing Standards
Collaborators/ ACES Power
Marketing
Affirmative
The modifications to PRC-004-2.1 R2 could be interpreted as requiring the GO to
analyze Protection System Misoperations on the generator interconnection Facility
even if it does not own the Facility. We suggest modifying the requirement as shown
below to address this issue.”The Generator Owner shall analyze Protection System
Misoperations on its generator and generator interconnection Facility that it owns ...”
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
SERC Reliability Corporation
Affirmative
With the understanding the Generator Interconnection FAcilities will be grouped with
Transmission Protection Systems for analysis at the regional level.
Response: Thank you for your comment and support.
Entergy Services
We suggest that the Vegetation Management Standards should be consistent for
both the TO and GO facilities. We would also like to suggest an additional
Recommendation for added clarity regarding Category 3 Outages (Off-ROW Fall-in
Outages). We understand that the Category 3 Outages are not a violation of the
Standard, but we feel that there should be some level of comment added within the
Standard clearly stating that these Outages are “Reportable Only” during the
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Quarterly Outage reports to the RE’s, and that there are no associated
violations/sanctions for this Category Of Outage, and that an Off-ROW fall-in outage
would not be considered an encroachment into the MVCD in any way. The Technical
Reference Document does a good job of clearly stating this in the Introduction on
Page 5 (“This standard is not intended to address outages such as those due to
vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human
activities or acts of nature.”) and we feel that this should also be stated clearly in the
Standard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
The remainder of your comment is outside the scope of this SDT.
Southern Company
We agree with the 2010-17 Standard Drafting Team’s conclusion to not modify other
standards such as those mentioned on page 4 of the Technical Justification document.
In additon, we wish to provide the following support for exclusion of these specific
standards. Southern Company believes NERC’s Project 2010-07 SDT must challenge
making revisions to the standards included in the FERC order on Cedar Creek and
Milford. (This order supports NERC’s requirement for those entities to register as a
TO/TOP due to their ownership of generator interconnection circuits > 100kV.) We
believe there are clear technical and reliability-based reasons that support not adding
GO and GOP requirements to these standards and not requiring the GO or GOP to
register as a TO or TOP. Furthermore, we also believe there are clear distinctions
between GO/GOP responsibilities and TO/TOP responsibilities that must be
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maintained to ensure BES reliability. Revising standards to assign TO/TOP
responsibilities to a GO/GOP or requiring a GO/GOP to register as a TO/TOP because
of generator interconnection circuits > 100kV will reduce the clarity of these
responsibilities. We have provided specific comments on each standard below:
EOP-005-1 R1, R2, R6, R7R1 and R2 require each TOP to have and maintain a system
restoration plan. R6 requires the TOP to train its operating personnel in
implementing this plan. R7 requires the TOP to verify its restoration plan by actual
testing or simulation. These requirements are clearly the role and responsibility of
the TOP, not a GO/GOP who happens to have generator interconnection facilities in
the TOP’s control area. The GOP’s roles and responsibilities are clearly and
appropriately addressed EOP-005-2. The presence of a generator interconnection
circuit > 100kV that happens to be owned by the GO instead of the TOP
fundamentally does not change the roles and responsibilities of the TOP or the GOP.
Thus, no changes due to EOP-005 are needed.
FAC-014-2, R2: FAC-014-2 R2 states “The Transmission Operator shall establish SOLs
(as directed by its Reliability Coordinator) for its portion of the Reliability Coordinator
Area that are consistent with its Reliability Coordinator’s SOL Methodology.” FAC014-2 R2 should not be revised to include GOPs. The GO is required by FAC-008-1 R1
and FAC-009-1 (FERC approved version) and pending FAC-008-3 R3 and R6 (FAC-008-3
filed with FERC for approval) to document the Facility Ratings for a GO-owned
generator interconnection circuit >100kV. The established Facility Rating must
respect the most limiting applicable equipment rating in the circuit and must consider
operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the GO to
the GOP if they are not the same entity. The operating voltage limits for this circuit
are established by the applicable TO/TOP, not the GO or GOP. Therefore, we believe
adding the GO to FAC-014-2 R2 would be redundant.
PER-003-1 R2, R2.1, R2.2PER-003-1 R2 and its sub-requirements state:”R2. Each
Transmission Operator shall staff its Real-time operating positions performing
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Transmission Operator reliability-related tasks with System Operators who have
demonstrated minimum competency in the areas listed by obtaining and maintaining
one of the following valid NERC certificates (1 ) : [Risk Factor: High][Time Horizon:
Real-time Operations]: R2.1. Areas of Competency R2.1.1. Transmission operations
R2.1.2. Emergency preparedness and operations R2.1.3. System operations R2.1.4.
Protection and control R2.1.5. Voltage and reactive R2.2. Certificates o Reliability
Operator o Balancing, Interchange and Transmission Operator o Transmission
Operator This requirement is specifically for TOPs. Personnel training for GOPs needs
to be addressed separately and not mingled with responsibilities of the TOP. The
GOPs role in supporting BES reliability needs to be clearly understood and defined
prior to establishing training requirements in the standards.
PRC-001-1, R2, R2.2, R4, R6Generator Operators (GOPs) and the scope of protection
equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirement R2 and sub-requirement R2.2 The
language used in requirement R2 which applies to the GOP uses the general terms
“relay or equipment failures” which would include not only generator relaying, but
generator interconnection relaying in the GOPs scope as well. The GOP is required to
notify the TOP and Host BA in R2.1 “if a protective relay or equipment failure reduces
system reliability.” Requirement R2.2 requires the affected TOP to notify its RC and
affected TOPs and BAs. Thus, applying R2.2 to a GOP would be redundant to R2.1.
Requirement R4 states, “Each Transmission Operator shall coordinate protection
systems on major transmission lines and interconnections with neighboring
Generator Operators, Transmission Operators, and Balancing Authorities.” A
generator interconnection tie line does not constitute a ‘major tie line” or major
“interconnection with neighboring GOPs, TOPs, and BAs.” Thus, R4 should not be
revised to include GOPs. If a GO exists within NERC that does own such
interconnection facilities, the responsibility for coordination of protection systems on
such a line or interconnection should be the responsibility of the TOP in that area, not
the GO/GOP. This may require formal agreements between the TO/TOP and GO/GOP,
since the GO may own protection equipment on his end. The same logic applies to
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R6. R6 states, “Each Transmission Operator and Balancing Authority shall monitor the
status of each Special Protection System in their area, and shall notify affected
Transmission Operators and Balancing Authorities of each change in status.” This is
clearly the responsibility of the TOP and/or BA, not a GO/GOP who happens to have
generator interconnection facilities in the area. An SPS function by definition is to
maintain BES reliability. If a GO/GOP has equipment within the equipment scope of a
Special Protection System (SPS), responsibility for monitoring the SPS should be
conveyed in a formal agreement as appropriate.
TOP-001-1 R1Requirement R1 states, “Each Transmission Operator shall have the
responsibility and clear decision-making authority to take whatever actions are
needed to ensure the reliability of its area and shall exercise specific authority to
alleviate operating emergencies.” This is clearly the responsibility of the TOP, not a
GO/GOP who happens to have generator interconnection facilities in the TOP’s area.
Thus, R1 should not be applied to a GO/GOP who owns or operates generator
interconnection facilities. Furthermore, TOP-001-1 R3 (proposed to be covered in the
future in the proposed IRO-001-2 R2 and R3) appropriately requires the GOP to
comply with reliability directives issued by the TO “unless such actions would violate
safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the TOP the necessary decision-making authority over operation of all
generator Facilities up to the point of interconnection. They also give the GOP the
necessary authority to take appropriate actions to ensure safety and protection of the
GO’s equipment. Thus, no changes to TOP-001-1 are necessary.
TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4Requirement R6 and its sub-requirements state:
“R6. Transmission Operators, individually and jointly with other Transmission
Operators, shall develop, maintain, and implement formal policies and procedures to
provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional
reliability, including:R6.1. Monitoring and controlling voltage levels and real and
reactive power flows.R6.2. Switching transmission elements.R6.3. Planned outages of
transmission elements.R6.4. Responding to IROL and SOL violations.”These are clearly
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the responsibility of the TOP, not a GO/GOP who happens to have generator
interconnection facilities in the TOP’s area. Thus, these requirements should not be
applied to a GO/GOP who owns or operates generator interconnection facilities. The
same logic applies here as stated above in our discussion on TOP-001-1. We believe it
is inappropriate and would be adverse to BES reliability to apply these requirements
to a GOP. TOP-004-2 effectively gives the TOP the necessary decision-making
authority over operation of all generator Facilities up to the point of interconnection.
They also give the GOP the necessary authority to take appropriate actions to ensure
safety and protection of the GO’s equipment, such as opening high voltage generator
output breakers when required to protect the unit. Thus, no changes to TOP-004-2
are necessary.TOP-006-2 R3Requirement R3 states, “R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall provide appropriate technical
information concerning protective relays to their operating personnel. The intent of
this requirement when applied to a GOP is already addressed in PRC-001-1 R1 which
states, “Each Transmission Operator, Balancing Authority, and Generator Operator
shall be familiar with the purpose and limitations of protection system schemes
applied in its area.” Thus, no change to TOP-006-2 is necessary.   
Response: Thank you for your comment and support. We agree that there are clear and technical reliability-based reasons that
support not adding GO and GOP requirements to these standards and not requiring the GO or GOP to register as a TO or TOP. We
have expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement
cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and many of your explanations are
included therein.
American Wind Energy
Association
AWEA appreciates the opportunity to submit these comments on the NERC Project
2010-07. AWEA supports the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
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would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. AWEA supports the intent and goal of the SDT to ensure
that all generator-owned Facilities are appropriately covered under NERC’s Reliability
Standards. We also agree with the SDT that while many GO/GOPs operate Elements
and Facilities that might be considered by some entities to be Transmission, these are
most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore,
we support the SDT’s approach of identifying a very limited number of TO/TOP
standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP owners
of generator lead lines. We would be concerned, however, if additional requirements
were added beyond FAC-001, FAC-003, and PRC-004. Consideration of any additional
standards with respect to generator lead lines should be done on a standard-bystandard basis, reviewing the applicability of each standard as well as the impact on
the reliability of the Bulk Electric System.
Response: Thank you for your comment and support.
Bonneville Power
Administration
BPA thanks you for the opportunity to comment on Project 2010-07, Generator
Requirements at the Transmission Interface. BPA stands in support of the proposed
revisions and has no comments or concerns at this time.
Response: Thank you for your comment and support.
Constellation Power Source
Generation
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. While the revision process focuses on specific standards, it is
important to consider the reliability questions in the context of the full complement
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of reliability standards that apply to entities. For instance, the following standards
already apply to generators and relate to the reliability considerations around
transmission at the generator interface:
o PRC-001-1 addresses coordination of protection system components by requiring all
GOs to ensure coordination of their protection system with interconnected parties.
Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA, etc.
o PRC-004-1 requires all GOs to ensure that they analyze all misoperations on their
protection system which would include the protection of the tie line.
o TOP standards applicable to GOs aid coordination between a GO and a TO with
regards to the generator tie line by requiring all GOs to coordinate all maintenance
and emergency outages (both forced and planned) with all applicable interconnected
parties. Further, all ISO procedures require the same of GOs.
o RC, TOP and/or BA certified operators control and are responsible for overseeing
that transmission. According to the NERC functional model, a Generator Operator is
defined as “operat(ing) generating unit(s) and perform(ing) the functions of supplying
energy and reliability related services.” Given this limited scope, the Generator
Operator (GOP) cannot be considered as operating on the same level as the Reliability
Coordinator, Transmission Operator or Balancing Authority when it comes to real
time information on the status of the BES. The GOP does not monitor and control the
BES, rather the GOP only monitors and controls the generators that it operates and
relays information to other operating entities.
o IRO and TOP standards applicable to GOs include tie lines in their pool of resources
to alleviate operational emergencies by requiring all GOs to operate as directed by
their TOP, BA, or RC as directed and must render emergency assistance.
o FAC-8 and FAC-9 manage rating methodology consistency by requiring all GOs to
develop a methodology to rate all equipment, and that the RC has the authority to
challenge the GO on that methodology. The onus is on the GO to either change their
methodology and rating accordingly, or provide a technical justification as to why
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they cannot adopt the changes. Further, a generator will never be limited by its tie
line, as a generator’s profits are directly tied to its output. Therefore no generator
would limit its facility to the equipment that is delivering that output.
Response: Thank you for your comment and support. We agree that it is important to consider the reliability questions in the context
of the full complement of reliability standards, and we have endeavored to make these broader connections clear in our revised
technical justification document (posted under “Supporting Materials”). That document has been expanded to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and the kinds of further
justifications you also provided are included therein. After another thorough review of these standards, the SDT continues to believe
that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
Cowlitz County PUD
In answer to the SDT request for feedback on FERC's Order concerning Cedar Creek
and Milford, the District finds no technical reason to add any of the listed standard
requirements, and struggles to understand why FERC would even consider this listing
as applicable.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc.
In section 4.2.1 of the Applicability Section, “within” should be “with”. Because
NERC’s Glossary of Terms establishes that an Agreement can be verbal and not
enforceable by law, section 4.2.1 should be further modified to clarify that it is a
legally enforceable and fully executed Agreement. The language in R3 in parenthesis
after Generation Owner should be modified to “once required by Requirement R2”.
This makes it clearer that R3 does not apply until the GO has an executed Agreement
to evaluate a request by a third part to interconnect.
Response: Thank you for your comment. We agree that “within” should be “with.” The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
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Manitoba Hydro
Question 10 Comment
Manitoba Hydro would also like to point out that if the redline changes are
implemented, it will greatly increase the complexity of coordination required under
FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Compliance & Responsbility
Organization
NextEra Energy, Inc. (NextEra) appreciates the work of the Project 2010-07 Generator
Requirements at the Transmission Interface Standard Drafting Team (SDT) on a
subject that NextEra has a significant interest in resolving. In fact, NextEra has been a
member of the SDT and an active observer. Given the recent events - such as (a) the
North American Electric Reliability Commission's draft interim directive; (b) the denial
of the Milford and Cedar Cheek requests for reconsideration at the Federal Energy
Regulatory Commission (FERC) and (c) the record in this case which, at times, suggests
the SDT needs to more formally consider the Milford and Cedar Cheek Reliability
Standards - NextEra requests that SDT more formally consider the merits of each
Reliability Standard adopted the Milford and Cedar Cheek FERC orders and the NERC
draft interim directive. Although NextEra does not condone the manner in which
NERC issued the interim draft directive and stated so in its comments to NERC on the
interim draft directive, NextEra’s overarching objective on this issue is to bring a
uniform, fair and technically supported approach that resolves the interface issue.
Thus, NextEra requests that the SDT (prior to proceeding any further or any additional
comments or votes on specific draft Reliability Standards) issue a technical paper that
point-by-point addresses the merits of including the Reliability Standards set forth in
the FERC Orders and NERC’s draft interim directive, and request stakeholder,
including NERC staff, comment. For example, this technical paper would likely the
merits of NERC’s draft interim directive not requiring NERC-certified operators (but
require training of interface operators), while FERC’s orders require NERC-certified
operators. While NextEra does not agree five days of training is necessary for an
interface operator, as the draft interim directive appears to propose, NextEra does
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believe a technical case can be made why NERC-certification is not required, and that
some degree of training related to the applicable Reliability Standards is reasonable.
Similar, on FAC-003 (as well as several other Standards), the draft interim directive
proposes a slightly different approach than the SDT. NextEra would rather these
approaches reconciled than be in conflict, with the potential for continued conflict as
the SDT’s work product proceeds. Further, NextEra requests that the SDT’s review
the technical merits of NERC’s proposed criteria to determine what generator
transmission lead is required to comply with additional Reliability Standards. As
noted, above, this technical paper should be posted for stakeholder, including NERC
staff, comment. Accordingly, while NextEra would have preferred that NERC and the
Regional Entities express there interim draft directive approach on the record in this
proceeding, NextEra believes it is appropriate for the SDT to draft a comprehensive
technical paper that, with an open approach, considers the inclusion of additional
Reliability Standards, if appropriate, as a way of building lasting support for its
approach.
Response: Thank you for your comment and support. We certainly agree that is important for NERC staff and the SDT to continue to
work together to try to develop a mutually agreed upon solution for dealing with this reliability gap, and to a certain extent, the SDT
has tried to provide the kind of technical paper you suggest in its modified technical justification document (posted under “Supporting
Materials”), which has been expanded to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by
NERC in its draft compliance directive. The SDT does not, at this point, plan to develop a technical paper that discusses the merits of
the standards introduced by FERC and NERC, because its current focus is on filing the FAC-001-1, FAC-003-3, and PRC-004-2.1a with
FERC. As it moves forward to a final solution, however, this kind of technical paper may prove useful. We appreciate the suggestion.
Dominion
No
Tennessee Valley Authority
No
Exelon
PRC-004 - suggest that the Standard state that responsibility for the analysis of
missoperations of protective equipment shall be the responsibility of the owner of the
protective equipment.
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Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
ReliabiltiyFirst
ReliabilityFist has found a number of editiorial erros for the FAC-001-1 VSLs. They
include the following:1. VSL R1 - should not reference sub-requirements, should
reference the sub-parts consistent with the requirement (i.e. Requirement R1, Part
1.1, 1.2 or 1.3) 2. VSL for R3 - the VSL should referenced Requirement 3, Part 3.1.1
through 3.1.16 rather than what is currently stated (Requirement R3, Part 3.1.1
R3.1.6)
Response: Thank you for your comment. While we agree that the VSLs for R1 need to be updated, that change is outside the scope of
this SDT because our changes are limited to those that incorporate the GO into the applicability of the requirement; the team made
no changes to R1 as it only includes the TO. We have, however, made the suggested changes to the VSLs for R3.
RES Americas Development
RES and AWEA appreciates the opportunity to submit these comments on the NERC
Project 2010-07. We support the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. RES and AWEA supports the intent and goal of the SDT to
ensure that all generator-owned Facilities are appropriately covered under NERC’s
Reliability Standards. We also agree with the SDT that while many GO/GOPs operate
Elements and Facilities that might be considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as
such should not be subject to the same standards applicable to TO/TOPs, who own
and operate Transmission Elements and Facilities that are part of the integrated grid.
Therefore, we support the SDT’s approach of identifying a very limited number of
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Yes or No
Question 10 Comment
TO/TOP standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP
owners of generator lead lines. We would be concerned, however, if additional
requirements were added beyond FAC-001, FAC-003, and PRC-004. Consideration of
any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the
impact on the reliability of the Bulk Electric System.
Sempra Generation
Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
SERC Planning Standards
Subcommittee/ SERC OC
Standards Review Group
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
6
END OF REPORT
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
7
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07: PRC-005-1.1a
The GOTO Drafting Team thanks all commenters who submitted comments on the first formal posting
for PRC-005-1.1a, part of Project 2010-07—Generator Requirements at the Transmission Interface.
Overwhelmingly, commenters approved the standard as written, and the team appreciates that
support. These standards were posted for a 45-day public comment period from March 2, 2012
through April 16, 2012. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 19 sets of comments, including
comments from approximately 65 different people from approximately 38 companies representing 9 of
the 10 Industry Segments as shown in the table on the following pages.
A few commenters did not support the use of the term
“generator interconnection Facility” without a formal
definition. Based on comments received elsewhere in this
project, the SDT has avoided the creation of new NERC
glossary terms, and has received significant industry
support for that strategy. While it is possible that other
language could have been used, the SDT believes the
reference “generator interconnection Facility” is clear.
Note: PRC-005-1b was approved by
FERC on March 14, 2012. Thus, the
changes the SDT proposes will be
applied to that version of the
standard. To reduce confusion, the
SDT’s modified standard is still
referred to as PRC-005-1.1a below,
but all other documents going
forward will be appropriately
updated to reference PRC-005-1.1b
and incorporate the associated
interpretation.
Some commenters are concerned about the changes
proposed in PRC-005-1.1a given the fact that PRC-005-2 is
also being revised. PRC-005-2 does not have the same
issues as PRC-005-1, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of Trustees, the SDT
wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard.
That portion of the standard was modified by NERC staff during the quality review to add boilerplate
compliance language recently approved by NERC legal staff. Modifying it further is outside the scope of
this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing
PRC-005-1a. As noted in the text box above, going forward, all references to PRC-005-1.1a will be
changed to refer to PRC-005-1.1b.
Some commenters stated that the addition of “generator interconnection Facility” was unnecessary
because that Facility is already considered part of the Generator Owner’s assets. While the SDT
believes that Generator Owners do treat the generator interconnection Facility as one of their assets,
commenters in previous postings suggested that adding “generator interconnection Facility” could add
clarity to the specific language in PRC-004 and PRC-005. It was pointed out to the SDT that language in
the requirements of PRC-004 and PRC-005 differed from PRC-001-1, so if the requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only
responsible for analyzing its generator Protection Systems, exclusive of its generator interconnection
Facility Protection Systems under PRC-004 and PRC-005 (whereas this interpretation wasn’t a risk
under PRC-001).
PRC-001-1 used language that had more a more broad application as noted below:
• R1 – “…shall be familiar with the purpose and limitations of protection system schemes applied
in its area.”
• R2 – “…shall notify reliability entities of relay or equipment failures as follows...”
• R3 “…shall coordinate new protective systems and changes as follows…”
PRC-004-2a and PRC-005-1b originally used language which could be construed as being more
restrictive (as shown below):
• PRC-004-2a@R2 – “The Generator Owner shall analyze its generator Protection System
Misoperations...”
• PRC-005-1b@R1 – “…each Generator Owner that owns a generation Protection System…”
• PRC-005-1b@R2 – “…each Generator Owner that owns a generation Protection System…”
The SDT agreed with the comments and modified the standards accordingly.
Other minority comments are addressed alongside their specific comments below.
The SDT considered all stakeholder comments submitted and determined that, save for the update to
reference PRC-005-1.1b instead of PRC-005-1.1a, no additional changes are necessary. The standard
will be posted for a recirculation ballot.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection
Facility” in Requirements R1 and R2 of PRC-005-1.1a. While there was no reliability gap in the
previous version of the standard, if the Requirements were applied literally, there was the
possibility for the misperception that the Generator Owner was only responsible for analyzing its
generator Protection Systems, exclusive of its generator interconnection Facility Protection
Systems. The clarifying changes to R1 and R2 make clear that generator interconnection Facilities
are also part of Generator Owners’ responsibility in the context of this standard. Do you support
the addition of the phrase “or generator interconnection Facility” to accomplish this clarification?
…. ......................................................................................................................................................... 9
2.
Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 13
Consideration of Comments: Project 2010-07 PRC-005-1.1a
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Jesus Sammy Alcaraz
Imperial Irrigation District (IID)
Additional Member Additional Organization Region Segment Selection
1. Jose Landeros
IID
WECC 1, 3, 4, 5, 6
2. Epi Martinez
IID
WECC 1, 3, 4, 5, 6
2.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
X
2
3
X
4
X
5
X
6
X
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6.
Mike Garton
Dominion Resources Services, Inc.
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
NPCC 1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc.
Group
Additional Member Additional Organization
Region
5
6
7
X
X
X
X
X
Segment Selection
1.
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
4
3
Southwest Power Pool Standards
Development Team
Jonathan Hayes
3
NPCC 5
10. Michael R. Lombardi Northeast Utilities
3.
2
Consideration of Comments: Project 2010-07 PRC-005-1.1a
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Dean
5.
Bender
Group
WECC 1
Mike Garton
Dominion- NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
6
2. Louis Slade
NERC Compliance Policy SERC
5
3. Michael Crowley
Electric Transmission
SERC
1, 3
4. Sean Iseminger
Fossil & Hydro
SERC
6
5. Chip Humphrey
Fossil & Hydro
NPCC 6
6. Jeff Bailey
Nuclear
MRO
6.
Group
Jean Nitz
Additional Member
6
ACES Power Marketing Standards
Collaborators
Additional Organization
X
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power, Inc
2. Scott Brame
North Carolina Electric Membership Corporation SERC
RFC
1, 3, 4, 5
3. Clem Cassmeyer
Western Farmers Electric Cooperative
1, 5
SPP
7.
Individual
Keira Kazmerski
Xcel Energy
8.
Individual
Dan Roethemeyer
Dynegy Inc.
9.
Individual
John Bee
Exelon
10.
Individual
Art Salander
HindlePower, Inc
11.
Individual
John Seelke
Individual
13. Individual
14.
3, 4
X
X
X
X
X
Public Service Enterprise Group
X
X
X
X
Martin Kaufman
Michelle R D'Antuono
ExxonMobil Research and Engineering
Ingleside Cogeneration LP
X
Individual
Dale Fredrickson
We Energies
15.
Individual
Michael Falvo
Independent Electricity System Operator
16.
Individual
Joe Petaski
Manitoba Hydro
12.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17.
18.
Individual
Individual
19. Individual
Thad Ness
American Electric Power
X
Darryl Curtis
Will Smith
Oncor Electric Delivery Company
MRO NSRF
X
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
3
X
4
5
X
6
7
X
8
8
9
10
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection Facility” in Requirements R1 and
R2 of PRC-005-1.1a. While there was no reliability gap in the previous version of the standard, if the Requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only responsible for analyzing
its generator Protection Systems, exclusive of its generator interconnection Facility Protection Systems. The clarifying
changes to R1 and R2 make clear that generator interconnection Facilities are also part of Generator Owners’ responsibility in
the context of this standard. Do you support the addition of the phrase “or generator interconnection Facility” to accomplish
this clarification?
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Over 90% of commenters
approved the standard as written, and the team appreciates that support.
A few commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility is clear, and no changes were made.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary and complicates the
ongoing development of PRC-005-2. The SDT believes that the clarifying language is necessary, and points out that if PRC005-1.1a proceeds to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because
the drafting team working on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended
March 28, 2012.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and incorporated that language prior to the last posting.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
9
Organization
Southwest Power Pool Standards
Development Team
Yes or No
Question 1 Comment
No
We would advise the Drafting team to take a look at the FERC OATT to
reconcile the term “generator interconnection facility “with Tariff term for
the LGIA. This should clarify the point of delineation and there should be no
misconception of the language as written.
Response: Thank you for the comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new terms. No change made.
Xcel Energy
No
Xcel Energy does not believe that trying to implement a revision of PRC-0051 at this point improves the reliability of the grid. There are better means of
clarifying the perceived “misperceptions” than drafting a standard revision.
This is particularly the case when PRC-005-2 is further along in the process
and is also posted for industry comment and ballot. The effort of the GOTO
SDT is counterproductive.
Response: Thank you for your comment. The SDT revised the standard based upon comments it received suggesting that it do so.
We do agree that there may have been alternative means to address the issue, such as a request for interpretation or CAN, but
given this was in the scope of the SAR, the SDT modified the standard to add the clarity recommended. If PRC-005-1.1a proceeds
to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because the drafting team working
on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended March 28, 2012.
ExxonMobil Research and
Engineering
No
The bulk electric system is contiguous. Therefore, any facility owned by the
Generator Owner that is used to connect the Generator Owner’s generation
facilities to the bulk electric system is already considered a bulk electric
system asset and part of the Generator Owner’s generation facilities. As
stated by in the question above, the addition of the term “or generator
interconnection Facility” does not resolve a reliability gap or add any
substance to the requirement
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
Consideration of Comments: Project 2010-07 PRC-005-1.1a
10
Organization
Yes or No
Question 1 Comment
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Kansas City Power & Light (Note:
Comment was manually added)
No
The phrase “generator interconnection” facility lacks definition making it
difficult to comment on the proposed change. It is important for the
standards and requirements to clearly delineate, define, or identify the
facilities or operating condition subject to application of the standards and
requirements.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation
of new terms. No change made.
Ingleside Cogeneration LP
Yes
Since PRC-005-1 already requires the Generation Owner to maintain and
test all their BES Protection System components, it seems to Ingleside
Cogeneration LP that the need to specify those which may trip the
interconnection facility as redundant. However, we do not believe that the
Standard Development Team’s modifications materially change the intent of
the Standard - nor can they lead an audit team to assign a double violation
for a single incidence of non-compliance.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Imperial Irrigation District (IID)
Yes
Northeast Power Coordinating
Council
Yes
Imperial Irrigation District (IID)
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
11
Organization
Yes or No
Bonneville Power Administration
Yes
Dominion- NERC Compliance Policy
Yes
ACES Power Marketing Standards
Collaborators
Yes
Dynegy Inc.
Yes
HindlePower, Inc
Yes
Public Service Enterprise Group
Yes
We Energies
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
American Electric Power
Yes
Oncor Electric Delivery Company
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
Question 1 Comment
12
2.
Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Overwhelmingly,
commenters approved of the standard as written, and the team appreciates that support.
Some commenters are concerned about the changes proposed in PRC-005-1.1a given the fact that PRC-005-2 is also
being revised. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are needed to that
standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of
Trustees, the SDT wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard. That portion of the
standard was modified by NERC staff during the quality review to add boilerplate compliance language recently approved
by NERC legal staff. Modifying it further is outside the scope of this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing PRC-005-1a. Going
forward, all references to PRC-005-1.1a will be changed to refer to PRC-005-1.1b.
Some commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility” is clear, and no changes were made.
One commenter was concerned that the addressing of a literal “reliability gap” should not be considered an errata
change. The SDT maintains that there is no actual reliability gap in the current standard language – just the possible
perception of one. The SDT and most stakeholders still believe that the clarifying change is a useful one, but it is
appropriate to classify as a minor change because it does not change the scope or intent of the associated standard. Still,
the SDT agrees that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to
its changes as errata.
One commenter was concerned that the standard as written does not allow for alternative testing programs in cases
where testing programs do not follow the ownership of the equipment. The SDT points out that an entity can enter into
an agreement (including a Coordinated Functional Registration) whereby another entity is assigned responsibility for
compliance with one or more requirements of one or more reliability standards without the standard itself being so
modified. The SDT therefore does not agree that this standard should be explicitly modified to allow what the commenter
suggests.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
13
One commenter was concerned about the statement that “no changes” were made to the VSLs. Because the SDT has not
proposed changes that affect the scope or intent of the current standard, no changes to the VSLs were necessary. The
same VSLs that have been approved by FERC (which can be found in the VSL matrix posted on NERC’s website:
http://www.nerc.com/page.php?cid=2|20|288) will remain in effect.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and modified the standards accordingly.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previously
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
One commenter encouraged the SDT to update the Effective Dates and Implementation Dates language to incorporate
the latest NERC legal boilerplate language. That change has been made.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Organization
Yes or No
Baltimore Gas & Electric
Company
Southwest Power Pool
Standards Development Team
Abstain
Yes
Question 2 Comment
Please refer to comments submitted by Exelon.
This effort seems to be redundant due to the work going on with PRC-005-2. We do
not understand why this change is being made and it wasn’t made very clear in the
red line changes or in this comment form background.
Response: Thank you for your comment. The Project 2007-17 Protection System Maintenance and Testing SDT is working on
comprehensive changes to PRC-005, as described in detail in the SAR posted on that projects webpage, while the Project 2010-07
Consideration of Comments: Project 2010-07 PRC-005-1.1a
14
Organization
Yes or No
Question 2 Comment
Generator Requirements at the Transmission Interface SDT is focused on making surgical revisions to standards where there might be
a reliability gap related to generator-owned Transmission Facilities. The current draft of PRC-005-2 does not have the same issues as
PRC-005-1 with respect to generator-owned Facilities, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT, the Project 2010-07 SDT wants to ensure that the
generator interconnection Facility is covered.
Bonneville Power
Administration
Yes
Regarding Section 1.3 Data Retention, BPA believes that it would be difficult for an
entity to provide “other evidence” to demonstrate compliance when the data
retention period is shorter than the time since the last audit. BPA requests the
drafting team to offer guidance as to what "other evidence" could be provided other
than what is already described in the measures. BPA believes that suggesting there
is some “other evidence” without providing a description leaves the TO’s and GO’s
without clear direction on how to comply with the standard. BPA suggests the data
retention period should be three years or since the time the last audit occurred,
whichever is longer for each TO and GO to retain evidence.Should the drafting team
revise the Data Retention language to reflect BPA’s concerns, BPA would vote in
favor of PRC-005-1.1a.
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
ACES Power Marketing
Standards Collaborators
Yes
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Exelon
Yes
The standard language should be clarified to allow for alternative testing programs,
agreed upon by both TO and GO, in cases where testing programs do not follow
ownership of the equipment for all Component Types so long as all of the protection
for the generator interconnection facility is covered.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
15
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. An entity can enter into an agreement (including a Coordinated Functional Registratyion)
whereby another entity is assigned responsibility for compliance with one or more requirements of one or more reliability standards
without the standard itself being so modified. The SDT therefore does not agree that this standard should be explicitly modified to
allow this. No change made.
ExxonMobil Research and
Engineering
Yes
The SDT has utilized two terms in this round of the drafting process whose
definitions are subject to interpretation. The terms ‘generating station switchyard’
and ‘generator interconnection Facility’ need to be defined to prevent inconsistent
enforcement or need for the development of a Compliance Application Notice. As
referenced in our comments to FAC-003-X/3, when you try to apply the term
‘generating station switchyard’ to an industrial complex that contains multiple
substations between the GSU and utility interconnection facility (another substation)
in order to measure the generator lead line for the 1 mile quota, there are several
candidates that appear to fit the criteria.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. While the SDT concedes there may be other language that could be used, the language posted has wide
industry support, therefore no change will be made.
American Electric Power
Yes
While we support changing the standard requirements as proposed, AEP offers the
following comments and suggestions.While the implementation plans states that
“there was no reliability gap in the previous version of the standard”, the previous
version of the standard, if applied literally, does indeed contain a reliability gap in
that it does not require Generation Owners that own a transmission Protection
System to have a Protection System maintenance and testing program. It is AEP’s
understanding that referring to the proposed revision as “PRC-005-1.1a” implies
errata from PRC-005-1a, and the announcement refers to “very limited revisions”. If
there is indeed a gap of responsibility in this standard, any changes to remediate
such a gap would not be errata, regardless of the amount of proposed changes in
content. As such, we recommend that the drafting team use a full revision naming
Consideration of Comments: Project 2010-07 PRC-005-1.1a
16
Organization
Yes or No
Question 2 Comment
convention for these proposed changes, i.e. PRC-005-2.In addition, making these
changes immediately effective would allow no opportunity for an entity to take the
proper steps to become compliant. We believe the revision should include an
implementation plan that allows industry adequate time to analyze their system and
complete any additionally required maintenance and testing activities.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is a useful one, but it is appropriate to classify as a
minor change because it does not change the scope or intent of the associated standard. Regarding the naming convention, the SDT
was advised that the errata naming convention would be acceptable to avoid confusion with the more complete set of revisions to
PRC-005 that are underway in Project 2007-17. The SDT had previously used the word “errata” to describe its changes, but agrees
that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to its changes as errata. No
change made.
Southern Illinois Power Coop.,
Brazos Electric Power
Cooperative, Inc.
Affirmative
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Pacific Gas and Electric
Company
Affirmative
The data retention period identified in D1.3 cannot be shorter than the time
between audits or the prior maintenance and testing interval
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
AEP Service Corp., AEP and
AEP Marketing, American
Electric Power
Affirmative
Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power
Consideration of Comments: Project 2010-07 PRC-005-1.1a
17
Organization
Yes or No
Question 2 Comment
Great River Energy
Affirmative
Great River Energy agrees with the comments of the MRO NSRF.
Dairyland Power Coop.
Affirmative
Please see comments submitted by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review Forum
Madison Gas and Electric Co.
Affirmative
Please see MRO NSRF comments.
Omaha Public Power District
Affirmative
Please see MRO NSRF Comments.
Brazos Electric Power
Cooperative, Inc.
Affirmative
See ACES Power Marketing comments.
Occidental Chemical
Affirmative
See comments submitted by Ingleside Cogeneration LP
Central Electric Power
Cooperative
Affirmative
See Matt Pacobit's comments from AECI
Southern Company Services,
Inc.
Affirmative
None
Alabama Power Company
Affirmative
None
Georgia Power Company
Affirmative
None
Gulf Power Company
Affirmative
None
Mississippi Power
Affirmative
None
Southern Company
Generation and Energy
Affirmative
None
Consideration of Comments: Project 2010-07 PRC-005-1.1a
18
Organization
Yes or No
Question 2 Comment
Marketing
Beaches Energy Services
Affirmative
Independent Electricity
System Operator
(No Comments.)
The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 of the draft standard and P. 1
of the Implementation Plan, to the following effect:”, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.”
Response: Thank you for your comment. The language you cite has been approved by NERC legal and has been updated in the
Effective Dates section and in the Implementation Plan.
Sunflower Electric Power
Corporation
Negative
A new term is introduced that is not a NERC defined term, the term is generator
interconnection Facility. The term was inserted without comment and clearly is
intended to include something that is not covered by the Standard. This new term
should be removed or defined in Glossary of Terms so entities may understand just
what is covered by this new term. The Implementation Plan for PRC-005-1.1a should
be updated to reflect the retirement of currently effective PRC-005-1b instead of
PRC-005-1a. PRC-005-1b became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. The SDT purposefully did not create a new term (note that only Facility is capitalized, while generator and
interconnection are not). No change made.
Seminole Electric Cooperative,
Inc.
Negative
a) Section D.2 Violation Severity Levels (no changes) - The standard should stand on
its own, therefore, just stating that the VSLs have "(no changes") is incomplete and
will lead to confusion. Please provide definition and clarity to this section.
Response: Thank you for your comment. The SDT has not proposed changes that affect the scope or intent of the current standard,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
19
Organization
Yes or No
Question 2 Comment
and because of that, no changes to the VSLs are necessary. The same VSLs that have been approved by FERC (which can be found in
the VSL matrix posted on NERC’s website: http://www.nerc.com/page.php?cid=2|20|288) will remain in effect. No change made.
Austin Energy, City of Austin
dba Austin Energy
Negative
Adding the words "generator interconnection" to the Facility description does not
add clarity to the Standard. PRC-005-1 is clear as written, indicating the actual owner
of a device supporting the BES is responsible for performing the actions necessary to
comply with PRC-005. The term "generator interconnection" is not defined and
introduces confusion, making responsibility for the application of the Requirements
less clear.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is useful. No change made.
Kansas City Power & Light Co.
Negative
Concerns have been expressed in the Standard comment forms provided by NERC.
Tucson Electric Power Co.
Negative
It would be difficult for an entity to provide "other evidence" to demonstrate
compliance when the data retention period is shorter than the time since the last
audit. Suggest that the data retention period language should be modified to "three
years or since the time the last audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
Bonneville Power
Administration
Negative
Please refer to BPA's comments submitted separately.
Manitoba Hydro
Negative
Please see comments submitted by Joe Petaski (Manitoba Hydro)
Xcel Energy, Inc.
Negative
Xcel Energy sees this project as counter-productive to the efforts of the Protection
Consideration of Comments: Project 2010-07 PRC-005-1.1a
20
Organization
Yes or No
Question 2 Comment
System Maintenance and Testing Standard Drafting Team that currently has PRC005-2 posted for comment and successive ballot.
Response: Thank you for your comment. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are
needed to that standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT,
we want to ensure that the generator interconnection Facility is covered.
City and County of San
Francisco
Negative
This revision should be used as an opportunity to clean up language relating to the
data retention period for PRC-005. The following language has been suggested and
appears consistent with the actual data retention period needed for all functional
registrations encompassed by this Standard: "three years or since the time the last
audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Other changes are outside the scope of the SDT.
HindlePower, Inc
No
I beleive that the requirments as shown in 1-4a - c need to be better clarified as to
the actual tasks required. There seems to be no real distinction between Verification
and inspection. There is no clear reporting structure and the requirment to
substitute Ohmic readings vs. discharge test is not basede on any industry reliable
standards. since there is much debate in the industry as to the validity if Ohmic
testing and it has not been accepted by the IEEE as an acceptbale practice I would
rather see terms in line with either IEEE standard or manufacvturer's
recommendations.
Response: Thank you for your comment. The SDT believes these comments may have been intended for the Project 2007-17 drafting
team which is making comprehensive revisions to PRC-005-2. The comment will be forwarded to that team by NERC staff.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project2010-07 in
general. If a Generator Owner is required to register as a TO, all theRequirements
applicable to a TO should apply. There is no need to changespecific Reliability
Consideration of Comments: Project 2010-07 PRC-005-1.1a
21
Organization
Yes or No
Question 2 Comment
Standards to allow the Generator Owner to perform onlyselected TO functions.For
additional information, please see Manitoba Hydro's commentssubmitted in the
comment period ending November 18, 2011. Manitoba Hydrodoes not believe that
the SDT fully addressed our concerns in their responsesto our comments in that
commenting period.
Response: Thank you for your comment. The SDT must act within the scope of the SAR for this project. The comments appear to
indicate that the entity disagrees with the SAR although they cite the Technical Justification document. The Technical Justification
document is meant to be used to show how the SDT arrived at its decisions to revise only 4 reliability standards as opposed to all that
were originally include in the Ad Hoc report, or those in the cited FERC orders.
MRO NSRF
Section D, Article 1.3 Data Retention states that the entities retain evidence for the
entire audit period since the last audit. Furthermore, in the 2nd paragraph of Article
1.3, it states that an entity “shall retail evidence of the implementation of its
Protection System maintenance and testing program for three years.”
If an entity is to prove compliance related to R2.1 and R2.2 of PRC-005-1.1a, the
NSRF recommends that Evidence Retention be revised to state “the two most
recent performance of each distinct maintenance activity for the Protection System
Components, or all performances of each distinct maintenance activity for the
Protection System Component since the previous scheduled audit date, whichever is
longer.”This agrees with the current draft in progress for PRC-005-2 Section D,
Compliance, Article 1.3, paragraph 4.
The NSRF is also concerned with those testing intervals, such as 12 years, which
would dictate a Registered Entity maintain 24 years of records, which is
unreasonable. This should be revised to have documentation for the most current
one testing interval, if after 06/18/07.
The NSRF believes that “the term “generation” in R1 and R2 should be changed to
“generator”. If changed, both Measures will need to be updated as well.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
22
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The Data Retention section was revised by NERC staff to add boilerplate compliance
language approved elsewhere. Thus, it is outside the scope of the SDT and no change was made.
In R1 and R2, the reference to “generation” was in the original standard, referring to a generation Protection System. While
“generator” may work better here, it is not within the scope of the 2010-07 SDT to change language outside the surgical insertion of
“generator interconnection Facility.”
Oncor Electric Delivery
Company
No
Imperial Irrigation District (IID)
No
Northeast Power Coordinating
Council
No
Imperial Irrigation District (IID)
No
Dominion- NERC Compliance
Policy
No
Xcel Energy
No
Dynegy Inc.
No
Public Service Enterprise
Group
No
Ingleside Cogeneration LP
No
Consideration of Comments: Project 2010-07 PRC-005-1.1a
23
Organization
Yes or No
We Energies
No
Question 2 Comment
END OF REPORT
Consideration of Comments: Project 2010-07 PRC-005-1.1a
24
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07 (FAC-003-3 and FAC-003-x)
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments on the second formal posting of FAC-003-3 and FAC-003-X, as part of Project
2010-07—Generator Requirements at the Transmission Interface. These standards were posted for a
30-day public comment period from March 9, 2012 through April 9, 2012. Stakeholders were asked to
provide feedback on the standards and associated documents through a special electronic comment
form. There were 22 sets of comments, including comments from approximately 83 different people
from approximately 76 companies representing 9 of the 10 Industry Segments as shown in the table on
the following pages.
The SDT considered all comments submitted and has proposed the following minor changes to FAC003-X and FAC-003-3:
•
•
FAC-003-X:
The Applicability section was reformatted to make it clear that the standard applies on a
Facility by Facility basis (as in FAC-003-3), not simply to all generator interconnection
Facilities owned by a Generator Owner with at least one qualifying generator
interconnection Facility.
In the Purpose section, Right-of-Way was capitalized because it is an approved NERC
glossary term and “North American Electric Reliability Council” was changed to “North
American Electric Reliability Corporation.”
Regional Entity was added back to the Applicability section of the standard. Requirement
R4 is assigned to the Regional Entity, and the Project 2010-07 does not have the
authority, based on the scope outlined in its SAR, to modify that requirement. Thus,
Regional Entity must remain in the Applicability section. In all cases, Regional Entity has
been spelled out rather than referred to as “RE.”
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
FAC-003-3:
A typo was found in the Severe VSL for R2; the previous reference to “Transmission
Owner” was changed to “responsible entity,” as in all other FAC-003-3 VSLs.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
Other minority comments are addressed alongside their specific comments below.
Note that if both FAC-003-X and FAC-003-3 are approved in this recirculation ballot, only FAC-003-3 will
be presented to NERC’s Board of Trustees. FAC-003-X has been modified so that the generator
interconnection Facility gap can be quickly addressed in the event that neither FAC-003-2 nor FAC-003-3
is approved by FERC.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_Rev%201_20110825.pdf.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
2
Index to Questions, Comments, and Responses
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder
comments submitted in the first successive ballot between October 5 and November 18, 2011,
along with advice from NERC staff. The SDT continues to believe that a reference to line of sight is
clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the line of sight
reference but made a few additional changes for formatting clarity and language consistency. The
team also added a footnote to further explain what it means by “line of sight.” Do you agree with
these changes? If not, please provide specific alternative language. …. ........................................... 8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Michael R. Lombardi Northeast Utilities
NPCC 1
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Don Jones
Group
2
3
4
5
6
7
Texas Reliability Entity
Texas Reliability Entity
ERCOT 10
2. David Penney
Texas Reliability Entity
ERCOT 10
3.
Group
Southwest Power Pool Standards
Development Team
Jonathan Hayes
Additional Member Additional Organization
Region
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
X
X
X
X
X
Segment Selection
1.
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Curtis Crews
8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Charles
Sheppard
1
2. Rebecca
Berdahl
3
5.
Group
Mike Garton
NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
5, 6
2. Michael Crowley
Electric Transmission
SERC
1, 3
3. Jeff Bailey
Nuclear
MRO
5
4. Sean Iseminger
F&H
SERC
5
5. Chip Humphrey
F&H
NPCC 5
6.
Group
WILL SMITH
MRO NSRF
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL(NSP)
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTLESON
OTP
MRO
1, 3, 4, 5
14. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
15. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
16. THERESA ALLARD
MPC
MRO
1, 3, 5, 6
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7.
Individual
Antonio Grayson
Southern Company
X
8.
9.
Individual
Individual
Brenda Frazer
John Bee
Edison Mission Marketing & Trading
Exelon
X
X
10.
Individual
Ray Phillips
Alabama Municipal Electric Authority
11.
Individual
Joe Petaski
Manitoba Hydro
12.
Individual
Dan Roethemeyer
Dynegy
13.
Individual
Thad Ness
American Electric Power
X
X
X
X
14.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
15.
Individual
Dale Fredrickson
Wisconsin Electric
16.
Individual
Daniel Duff
Liberty Electric Power LLC
17.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
18.
Individual
Brian Murphy
NextEra Energy, Inc.
X
19.
Individual
Jean Nitz
ACES Power Marketing
20.
Individual
Patrick Brown
Essential Power, LLC
21.
Individual
Russell A. Noble
Cowlitz County PUD
22.
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
X
X
X
X
X
X
X
X
X
7
X
X
X
X
X
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments submitted in the first
successive ballot between October 5 and November 18, 2011, along with advice from NERC staff. The SDT continues to
believe that a reference to line of sight is clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the
line of sight reference but made a few additional changes for formatting clarity and language consistency. The team also
added a footnote to further explain what it means by “line of sight.” Do you agree with these changes? If not, please provide
specific alternative language.
Summary Consideration:
Some commenters still do not support the qualifying language for Generator Owners (GOs) or believe that the qualifying
language should be worded differently. The SDT continues to believe that the qualifying criteria for GOs are appropriate;
it has explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant
stakeholder comments, including many possible language options, and is satisfied that it has determined the appropriate
language to address the reliability gap.
Some commenters suggested changes to items – including the content of the VSLs and the tables attached to the
standard that were outside the scope of the SDT’s work.
Some commenters raised questions about the language differences between FAC-003-X and FAC-003-3 and expressed
concern that the language in FAC-003-X could lead to a “null” result whereby the qualifying language is not applied
according to the SDT’s intent. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the language in
4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written, now that it has been reformatted to better match the formatting in FAC-003-3.
Some commenters questioned whether “clear line of sight” means from a fixed point or from any point along the line.
The SDT clarified that it intends for the phrase “from the generating station switchyard fence to the point of
interconnection” to mean that there is a clear line of sight from any point along that length of line.
One commenter questioned whether the standard applies to all generator interconnection Facilities that a GO owns if it
applies to one of them. The SDT clarified that it intended for the standard to apply on a line by line basis in both FAC-003X and FAC-003-3. To clarify this, it has reformatted the Applicability section of FAC-003-X to better match the formatting
in FAC-003-3.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
8
One commenter asked whether the standard applies to the entirety of an applicable generator interconnection Facility,
or just the portion of the line greater than one mile. The SDT clarified that if a GO owns an applicable line, the GO is
responsible for the entirety of that line. The SDT believes that this is clear in the standards as written.
One commenter expressed concern that the implementation timeframe is too long. The SDT reminded the commenter
that the time frame was based on previous stakeholder comments and the fact that the implementation of Version 0
standards – the transition into which marked the time that TOs needed to begin applying FAC-003 on a mandatory basis –
occurred over more than two years. It is therefore reasonable to assume that GOs, having never had to comply with a
vegetation management standard, be afforded adequate time to do so.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previous
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
The SDT considered all comments received and decided to address typos, improve the formatting of the Applicability
section of FAC-003-X, and update the boilerplate language in the Effective Dates sections of the standards and their
implementations plans. The SDT has proposed no substantive changes to the standards.
Organization
Yes or No
Question 1 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact,
one could argue that a very short line, 300 feet in length, that experienced a
fault from a tree at "the end of the circuit", i.e near the switchyard fence,
would have much more of an impact on the BES because the fault would be
limited by much less impedance.
(b) For the GO that owns several lead lines but only one of the lines is
greater than one mile in length, does this standard apply to all the lead lines
he owns? A response can be affirmative with the current language of the
section 4.2.1. If this is not the intent, it should be clarified.
(c) It is also unclear in this version if a GO that owned one line that was 1.2
miles in length would have to comply for the entire length of said line, or
just 0.2 miles of said line. If the GO is responsible for 1.2 miles, then that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Yes or No
Question 1 Comment
argues that the first mile is important and consequently there is no basis for
ignoring the first mile on other lines. If the GO is only responsible for 0.2
miles, what is the technical basis to ignore a mile? And would it be the first
mile from the switchyard that is ignored, or is the middle mile, or the last
mile where it connects to the TO? Or could the GO decide? Or could the GO
pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(d) The 2 year compliance time line is far too long. There is significant
industry evidence that was developed in the drafting of Version 2 that
supports a one year compliance time-line for new lines. This is evidenced in
Version 2. Thus there is no basis for the 2 years
Response: Thank you for your comment. The SDT continues to believe that the qualifying criteria for GOs are appropriate; it has
explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap.
The SDT intended for the standard to apply on a line by line basis in both FAC-003-X and FAC-003-3. To clarify this, it has
reformatted the Applicability section of FAC-003-X to better match the formatting in FAC-003-3.
If a GO owns an applicable line, the GO is responsible for the entirety of that line. The SDT believes that this is clear in the
standards as written.
With respect to the Implementation Plan, the SDT reminds Ameren that the time frame was based on previous stakeholder
comments and the fact that the implementation of Version 0 standards – the transition into which marked the time that TOs
needed to begin applying FAC-003 on a mandatory basis – occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do so.
BC Hydro and Power Authority
Negative
“BC Hydro agrees with the revisions to FAC-003-3 and would vote
Affirmative except for the following two items.
One: The FAC-003-2 adopted by the NERC Board of Trustees had a
significant change to what was voted on in Draft 6 in the Table of
Compliance Elements (R1 and R2). In the table on Page 13 of the version
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Organization
Yes or No
Question 1 Comment
adopted by the NERC Board of Trustees on November 3, 2011, the VSLs
were changed and the staff proposed violation severity levels were adopted
and the review team recommendations were rejected. Therefore, there is
no Low or Moderate VSLs for these two violations only High and Severe.
This was rejected earlier by a number of utilities including BC Hydro and was
not in the version 6 draft that was voted for on the last ballot. This change
as adopted is a concern as it expects a level of program perfection that
seems unrealistic. It is also at odds with the Rationale for R1 and R2 outlined
on Page 32 of the standard “Guideline and Technical Basis” section which
gives an explanation for the increasing levels of violation severity. Program
failures that were deemed to be “unusual conditions in an otherwise sound
program” or “not adequately addressed by the program” formerly rated as
Lower or Moderate VSL are now rated as High. It also extends the severity
of the violation beyond what is currently in FAC-003-1 although the levels of
non-compliance are not strictly comparable between versions. This change
is carried on in the Draft FAC-003-3.
Two: Table 2 (pg. 30 and 31 of FAC-003-3 Draft 3) for Minimum Vegetation
Clearance Distances for AC Voltages now includes clearance calculations for
287 kV which is good and was something BC Hydro asked for. However, the
calculations don’t seem to be correct as the limits are higher than for
345kV. BC Hydro recommends either providing an explanation as to why
these limits seem to be out of sequence to increasing voltage or recalculate
them.”
Response: Thank you for your comment. The SDT's SAR is very limited in scope (determining which additional standards should
apply to a GO/GOP). The SDT made no changes to the VSLs and simply included the FAC-003-2 VSLs that were approved by
NERC’s BOT, as those are the VSLs that will be filed with FERC. Similarly, the SDT made no changes to Table 2, as that would also
have been outside its scope; the SDT exclusively made changes that would add GOs or GOPs to standard requirements or
applicability sections, and changes that would bring the standard up to date according to current NERC templates. No change
made.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
11
Organization
Yes or No
Question 1 Comment
ComEd
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
PECO Energy
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
Gulf Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Mississippi Power
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Alabama Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Utility Services, Inc.
Negative
The applicability language under Version X is not the same as the language
in Version 3. We do not believe that applicability language in Version X can
ever result in a “True” logical outcome whereas the language in Version 3
can. We understand the intent; however, applying the specific language
using the logical "AND" in the applicability portion of the standard will
always come out with a null result. We suggest the SDT adopt the
applicability language in Version 3 in Version X.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
language in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that it has been reformatted to better match the formatting in FAC-003-3. No
change made.
Xcel Energy, Inc.
Negative
This project is counter-productive to the efforts of the Protection System
Maintenance and Testing Standard Drafting Team that concurrently has
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Organization
Yes or No
Question 1 Comment
PRC-005-2 posted for comment and successive ballot.
Response: Thank you for your comment. The SDT believes this comment was submitted in response to PRC-005 and will address
it with comments received under that standard.
SERC Reliability Corporation
Negative
We have concern that if this passes there will be BES Elements that will not
be covered by the vegetation management standard that are currently
included in the standards and that this determiniation is based solely on
ownership and not risk to reliability. SERC supports BES reliability and as
veggetation management was identified as a significant contributor to the
2003 Blackout we do not support a revision that would create a gap in the
results-based, defense-in-depth approach that has been determined to be
necesary for the reliable operation of the interconnected transmission
network.
Response: Thank you for your comment. GOs are not currently covered under any vegetation management requirements, so the
SDT does not understand the comment about removing coverage for BES Elements “that are currently included in standards.”
The applicability to TOs, the entity currently subject to vegetation management requirements, is not changing. The SDT
recognizes that in many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2) the
overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for exempting these Facilities
because incorporating them into FAC-003 would offer no reliability benefit. No stakeholder has commented that there are
similarly situated transmission facilities.
Southern Company
No
The requirement as worded implies or could be interpreted to mean one's
line of site would have to originate at the generating station switchyard
fence. The "clear line of site" should also include that from a roadway that
travels in proximity to the line. Such a roadway's purpose would likely
include access to the line for inspections, maintenance, travel from the
plant to the transmission subsation, etc. Since the terrain between the
generating station switchyard fence and the point of interconnection could
obsure the view from the fence, the clear line of site from such a roadway
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Organization
Yes or No
Question 1 Comment
should be allowed. The requirement should be revised to read, "...or (2)
does not have clear line of sight1 from the generating station switchyard
fence or a roadway to the point of interconnection with a Transmission
Owner's Facility."
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap. No change made.
Southwest Power Pool Standards
Development Team
No
Clear line of sight” means the distance that can be seen by the average
person “standing at ground level “without special instrumentation (e.g.,
binoculars, telescope, spyglasses, etc.) on a clear day.
Response: Thank you for your comment. The SDT has considered all relevant stakeholder comments and is satisfied that we
have determined the appropriate language to address the reliability gap.
Cowlitz County PUD
No
Cowlitz must agree with Exelon’s position insomuch that the vantage point
must be related to the generating station switchyard maintenance or the
operation and maintenance of the generation plant itself, and afford a clear
perspective of vegetation proximity. Cowlitz also agrees with the SDT’s line
of sight clarifying verbiage. However, restricting the vantage point to the
generating station switchyard fence does not encompass the spirit of the
exclusion. A short one-mile transmission interconnection line - from the
generating station switchyard to the interconnection point - that is
frequently viewed during the operation and maintenance of the generation
plant itself should be the crux of the exemption.
The exact location, i.e., the generating station switchyard fence, of the
vantage point is not the make or break of whether the interconnection line
will be routinely inspected by default. As an example, consider a hydro
project where the generating station switchyard may be located near the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
14
Organization
Yes or No
Question 1 Comment
tailrace inside a canyon. From the fence line of this particular switchyard,
only the interconnection line traversing up the canyon wall is visible.
However, topside of the dam where maintenance and operational
personnel must daily traverse under the interconnection line to access the
powerhouse and switchyard may afford a clear view of both the generating
station switchyard below and the interconnection station which includes
the whole interconnecting line in-between.
Further, if parts of the interconnecting line is viewable in two or even three
vantage points beneath the interconnection line during the normal transit
to and from the generating station switchyard, the sum of which comprises
the whole line, can this not also meet the spirit of the exclusion?
Conversely, Cowlitz does not hold that any vantage point should be
acceptable. Any vantage point that must require special effort to access no
matter the ease is not acceptable. Also, a perpendicular view of a line (not
under or near) complicates perception of the proximity of vegetation to a
line. Views parallel down the right-of-way maximizes perception of
vegetation proximity.
Further, a long line that is fully viewable during transit to and from the
generation plant increases the chance of hidden vegetation encroachment.
Cowlitz strongly opposes any trivializing of reliability compliance collateral
damage. Forcing compliance activities with no reliability return must be
avoided wherever possible. As a stakeholder with limited time to invest
reviewing all the comments submitted, Cowlitz offers an apology to Exelon
for missing their initial comment. Cowlitz commends Exelon’s persistence in
this matter.
***Suggested language: ...or (2) do not have a clear line of sight (leave the
footnote in place) up and/or down from a single vantage point within the
transmission right-of-way where both the origin at the generating station
switchyard and the termination interconnection point with the Transmission
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
15
Organization
Yes or No
Question 1 Comment
Owner’s Facility can be seen, and where operations or maintenance
personnel frequent on foot during normal generation plant or generating
station switchyard access is made...
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. We do not believe that adding the language you
suggest necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has considered all
relevant stakeholder comments and is satisfied that we have determined the appropriate language to address the reliability
gap. No change made.
Exelon
No
Exelon disagrees with the current proposed draft of FAC-003-3/X because
the reference to a “clear line of sight from the generating station switchyard
fence to the point of interconnection” does not clarify the Standard and is
unsupported by any technical basis. Furthermore, the definition of “clear
line of sight” added by the SDT does not address or remedy the substantive
concerns raised in Exelon’s appeal.
Exelon reiterates that the SDT should base the applicability of the Standard
on the length of the transmission line, a measurable component of the bulk
electric system, and remove all references to a “clear line of sight.” This
approach is consistent with previous draft versions of FAC-003 proposed by
the SDT and the Ad Hoc Group and the recent recommendation of the NERC
Vice President of Standards and Training in response to Exelon’s appeal.
Alternatively, if the “clear line of sight” verbiage remains, the Standards
should be clarified to remove the requirement that the line of sight be
established from “the generating station switchyard fence to the point of
interconnection” and to add a requirement or clarify that “clear line of
sight” for lines of one mile or less can include observation of the length of
the transmission lines from various vantage points within the owner
controlled property. The SDT states in the “Background” section of the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
16
Organization
Yes or No
Question 1 Comment
Unofficial Comment Form that “a reference to the line of sight is clarifying
and makes explicit the SDT’s implicit intent from day one.”
Yet, the SDT offers no support for its “implicit intent from day one,” and a
review of the history for these Standards certainly does not support an
“implicit intent from day one” to require a clear line of sight from a fixed
location, let alone the generating station switchyard fence, to the point of
interconnection. The Technical Justification document posted in September
2011 (p. 3) refers to the Ad Hoc Group’s original thought to exclude from
the Standards any transmission lines that were “less than two spans [long]
(generally one half mile from the generator property line).” In agreeing
“with that intended exclusion in principle,” the SDT explained (p. 3) that,
“[a]fter reviewing formal comments, the SDT agreed to revise the exclusion
so that it applies to a Facility [transmission line] if its length is ‘one mile or
1.609 kilometers beyond the fenced area of the generating station
switchyard’ to approximate line of sign [sic] from a fixed point,” (the fixed
point being the fenced area of the generating station switchyard). From the
start, the Ad Hoc Group and SDT focused on the length of the transmission
line (either a half mile as proposed by the Ad Hoc Group or a mile as
proposed by the SDT) as the proxy for line of sight, the presumption being
that up to a certain distance, the overhead line is in the line of sight at
various locations throughout the Generator Owner’s property and
reasonably subject to being managed through normal day-to-day plant
activities.
The SDT has not, until the most recent iteration of the Standards, focused
on requiring a “clear line of sight from the generating station switchyard
fence to the point of interconnection.” As support for adding the “clear line
of sight” requirement to the FAC-003-3/X Standards in December 2011, the
SDT noted as follows: “We believe that the one mile length is a reasonable
approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
17
Organization
Yes or No
Question 1 Comment
any discretion on the part of a Generator Owner or an auditor.” With the
addition of an explicit line of sight reference here, the SDT believes it has
clarified its original intent. (Side bar comments to FAC-003-3, Section 4.3.1
(December 1, 2011); FAC-003-X, Section 4.3.1 (December 1, 2011)).
This explanation does nothing more than (1) reiterate the point the SDT has
maintained throughout the entire drafting process, namely that “the one
mile length” of a transmission line “is a reasonable approximation of line of
sight,” and (2) explain that the SDT included a “fixed starting point” (the
fenced area of the generation station switchyard) from which to measure
the length of the transmission line to address stakeholder concerns about
excessive Generator Owner discretion with respect to the location from
which to take a measurement and inconsistent application of the Standards.
Again, the SDT’s “intent” (implicit or otherwise) “from day one” has nothing
to do with establishing a “clear line of sight from the generating switchyard
fence to the point of interconnection.” In addition, requiring a “clear line of
sight from the generating station switchyard fence to the point of
interconnection” is technically unsupported. The SDT just added the
requirement for a “clear line of sight to the point of interconnection”
language without considering the implications of why such a change was
required or reasonable. While a specific fixed starting point (the generating
station switchyard fence) and end point (the point of interconnection) may
make sense for establishing a starting and ending point from which to
measure the length of the transmission line (the one-mile limitation), it does
not make sense when considering a clear line of sight, especially in light of
stakeholder comments and the SDT’s repeated acknowledgment that in
many cases, generation Facilities are either (1) staffed and the overhead
portion is within the line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
18
Organization
Yes or No
Question 1 Comment
these qualifiers represent a reasonable and appropriate risk prevention
approach.(Consideration of Comments, Generator Requirements at the
Transmission Interface, Project 2010-07 (for November 9, 2011 successive
ballot), p. 1; Technical Justification Resource Document (posted March
2012), p. 3.)
By inserting the “clear line of sight” requirement now without modifying the
fixed starting point, the SDT completely ignores its unequivocal
acknowledgment that generation Facilities are unique in the sense that
personnel can see the line from various locations within the owner
controlled area and many generation Facilities are over paved surfaces. The
absence of a technical justification for imposing a “clear line of sight” is
illustrated by the following example.
A Generator Owner transmission line leaving the generating station could
take a “dog leg” turn (the line turns at one of the towers). Standing at the
tower in this example, an individual would have a clear line of sight of the
entire line to either end of the short-distance line (to the end leaving the
station and to the end terminating at the point of interconnection). Since
the generating Facility is within the Generator Owner’s property line or
controlled area and consistently staffed by personnel who patrol the owner
controlled area, the line can be observed and maintained by staff in the
same manner as any other short distance line with a “clear” line of sight
from the “generating station switchyard fence to the point of
interconnection.” Moreover, to the extent a portion or the entire length of
the line travels over paved surfaces or structures, any barriers or obstacles
to a clear line of sight will not be caused by vegetation, as discussed in FAC003-3/X but, rather, by equipment, components, or structures. Clearance
between generator lines and structures is already covered in other NERC
Standards. For those lines that do travel over areas of vegetation, the
regular personnel monitoring and surveillance of the areas over which the
lines travel provides reasonable assurance of protection from vegetation
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Organization
Yes or No
Question 1 Comment
related events.
Rather than clarifying the Standards, the SDT has introduced more
ambiguity into the Standards. The addition of the “generating station
switchyard fence” as the point of reference for a clear line of sight adds
more confusion than it solves by introducing a variable that will be left to
the discretion of generator owner and an auditor. What is the definition of
a “generating station switchyard fence?” As Exelon noted in its Appeal and
at least one other Registered Entity noted in its Comments for the first
successive ballot (Consideration of Comments posted March 2012, p. 38),
some generation facilities do not have generating switchyards or generating
switchyard fences. A requirement that there be a clear line of sight from the
“generating switchyard fence” is meaningless in cases where no such
switchyard or fence exists. Is it the fence surrounding the generating unit or
is it meant to refer to the fence surrounding the Transmission Owner’s
associated switchyard and relay house? What if there are multiple physical
fence lines between the generating unit and the point of interconnection?
In addition, by introducing a point of reference that is not a physical
component or measurable reference of the bulk electric system, what
precludes the Generator Owner from arbitrarily moving the fence line to
avoid applicability? Also lacking in clarity is the addition of a footnote
defining “clear line of sight” to mean “the distance that can be seen by the
average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.” Generation Owners will be left to
determine what constitutes an “average person,” a “clear day,” and “special
instrumentation.”
For all these reasons, Exelon requests that the SDT base the applicability of
the Standard on the length of the transmission line, a measurable
component of the bulk electric system, and remove all references to a
“clear line of sight.” Alternatively, if the “clear line of sight” verbiage
remains, the Standards should be clarified to remove the requirement that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
20
Organization
Yes or No
Question 1 Comment
the line of sight be established from “the generating station switchyard
fence to the point of interconnection” and to add a requirement or clarify
that “clear line of sight” for lines of one mile or less can include observation
of the length of the transmission lines from various vantage points within
the owner controlled property.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt.
The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that
there is a clear line of sight from any point along that length of line. We do not believe that adding a reference to a fixed
vantage point necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has
considered all relevant stakeholder comments and is satisfied that we have determined the appropriate language to address
the reliability gap. No change made.
Texas Reliability Entity
No
In FAC-003-X:
1. We appreciate that you took Regional Entity out of the Applicability
section, but there is still a Requirement (R4) that applies to the Regional
Entity. Is that Requirement intended to be enforceable against the Regional
Entities? We suggest removing Requirement R4.
2. In Part D.1.1, only the Regional Entity should be listed as Compliance
Monitor, since the Regional Entity has been removed as an Applicable
entity.
3. In the Purpose section, update the reference to NERC (use “Corporation”
instead of “Council”), and capitalize “Rights-of-Way” since it is a defined
term.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Question 1 Comment
4. We suggest that you spell out “Regional Entity” in Applicability part 4.2.1.
5. In the implementation plan, the reference to “R3” should be corrected to
“R1” in the following sentence: “In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of
the first calendar quarter one year following Board of Trustees adoption.”
In FAC-003-3:
6. There is no Compliance Monitor listed on page 17. At least the Regional
Entity should be listed here.
7. In the Severe VSL for R2, replace “Transmission Owner” with
“responsible entity.”
8. In the Severe VSL for R1 and R2, remove “active transmission line” before
“ROW.” That phrase is confusing in the VSLs because it does not appear in
the requirements, and it is not clear whether it is intended to change the
requirements.
9. In Table 2 (Alternating Current - meters AND Direct Current) the footnote
references are wrong. We think they should be 9 and 10, rather than 7 and
8.
10. In Table 2 (Direct Current), the column headings are wrong. Only the
first column heading should refer to voltage. The rest should refer to
MVCD.
Response: Thank you for your comment.
1. The SDT has reverted back to the original Applicability (which included the Regional Entity) because deleting a requirement
is outside the scope of this drafting team.
2. Because the Regional Entity was returned to the Applicability section, the second bullet in section D1.1 must remain.
3. Changes made.
4. Regional Entity has been spelled out in all cases.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Question 1 Comment
5.
6.
7.
8.
Change made.
The Compliance Enforcement Authority section has been updated as suggested.
Change made.
Modifying the VSLs beyond the change from “Transmission Owner” to “responsible entity” is not within the scope of the
SDT, and these VSLs have already been approved by NERC’s BOT.
9. These are 9 and 10 in both the clean version and the redline version.
10. The Project 2010-07 SDT did not modify this table.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project
2010-07. If a Generator Owner is required to register as a TO, all the
Requirements applicable to a TO should apply. There is no need to change
specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions.For additional information, please see Manitoba
Hydro's comments submitted in the comment period ending November 18,
2011. Manitoba Hydro does not believe that the SDT fully addressed our
concerns in their responses to our comments in that commenting period.
Response: Thank you for your comment. Under the SDT’s changes, GOs are not going to be required to register as TOs, so this
comment does not apply.
To reiterate our comments in previous comment reports, the intent of the SDT’s SAR is to address all reliability gaps associated
with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should
first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”
posted alongside the December ballot) – that is, a Facility used to connect one or more generators to a Facility owned or
operated by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection
Facility owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission
Interface Background Resource Document.
Liberty Electric Power LLC
No
The "line of sight" should be removed. It opens up the entity to a finding of
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
23
Organization
Yes or No
Question 1 Comment
non-compliance if a temporary blockage of line of sight should occur.
Response: Thank you for your comment. We maintain that the addition of the reference to “clear line of sight” is clarifying and
helps support the rationale behind the one mile exemption. A line less than one mile that passes through a dense grove should
not be exempt from this standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over
a paved surface should be exempt. Nothing in the proposed standard prohibits an entity from self-imposing the requirements
contained within in order to mitigate any perceived risk of potential non-compliance. No change made.
Northeast Power Coordinating
Council
No
The Applicability language used in FAC-003-X is different from that used in
FAC-003-3. The language used in FAC-003-X uses “and” in several places
which leads to confusion and a probable “null” result, whereas the language
in FAC-003-3 is more straightforward and makes use of “or”. The FAC-003-3
applicability language should be used in FAC-003-X.The explanation of what
is meant by line of sight should be incorporated in the Applicability Section
wording as standards, at NERC’s direction, are supposed to be getting away
from the use of footnotes.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
formatting in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that the formatting has been updated to better reflect the formatting in FAC-0033. No change made.
NextEra Energy, Inc.
No
Under the line of sight approach, a generation lead would be exempt from
the requirements of FAC-003-3 if personnel can see the generation lead
corridor and the generation lead is less than a mile. The rationale provided
to support of this proposal is that “Stakeholders have generally supported
the rationale for exempting these Facilities because incorporating them into
FAC-003 would offer no reliability benefit.”
However, there is no data that supports that generation leads of less than a
mile are categorically not subject to vegetation contacts and outages.
Further, in practice this approach will unduly discriminate against longer
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
24
Organization
Yes or No
Question 1 Comment
generator leads, many of which are associated with renewable energy
resource, such as wind and solar.
NextEra Energy Inc. (NextEra) believes a more technically sound approach is
that all generator leads be subject to FAC-003-3, with the opportunity to be
exempted from FAC-003-3 regulation upon an affirmative demonstration
that no vegetation threat exists.
To implement this approach, NextEra proposes that FAC-003-3 applicability
4.3.1 be revised to read as follows: “Overhead transmission lines, including
generation leads, beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner and
are:4.3.1.1. Operated at 200kV or higher; or 4.3.1.2. Operated below 200kV
identified as an element of an IROL under NERC Standard FAC-014 by the
Planning Coordinator; or. 4.3.1.3. Operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.”
NextEra would also propose to add a new section 4.3.2 that reads as
follows:”If a Generator Owner or Transmission Owner can demonstrate that
the entire Right-of-Way is paved or otherwise devoid of vegetation, and
reasonably expected to remain so, the Generation Owner or Transmission
Owner is exempt from FAC-003-3.”
In addition, NextEra proposes that the drafting team consider a megawatt
(MW) threshold for a generating plant from both a stand-alone and
aggregate bases. For example, it is unlikely that vegetation contact tripping
a 50 megawatt generator (or a generator of 100 MWs in the aggregate)
connected to a robust transmission system with a large amount of load and
generation will adversely impact reliability.
Thus, NextEra proposes the addition of a provision that exempts a
generation lead for stand-alone generators of 50 MWs and below and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
25
Organization
Yes or No
Question 1 Comment
generators in the aggregate of 100 MWs and below, unless there is an
affirmative request for the generator to comply with FAC-003-3 by a
Transmission Operator or Reliability Coordinator. Such a provision could
read as follows:”Unless a Transmission Operator or Reliability Coordinator
requests in writing that a stand-alone generator of 50 Megawatts (MWs) or
below (with a 200 kV or above generation lead) or a generator in the
aggregate of 100 MWs or below (with a 200 kV or above generation lead)
comply with FAC-003-3, these classes of generators and their associated
generation leads are exempt from complying with FAC-003-3. In the event a
Transmission Operator or Reliability Coordinator requests in writing that a
stand-alone generator of 50 Megawatts (MWs) or below (with a 200 kV or
above generation lead) or a generator in the aggregate of 100 MWs or
below (with a 200 kV or above generation lead) comply with FAC-003-3, the
associated registered entity shall have one-year from the date of the written
correspondence to come into compliance with FAC-003-3.”
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. And because there are many GOs whose lines would fall into these categories, the SDT believes the exemption is
necessary and prevents GOs with little to no reliability risk from incurring undue cost and compliance risk in the development
and maintenance of a vegetation management plan. In sum, the SDT has considered all relevant stakeholder comments and is
satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Dynegy
No
Using the switchyard fence is to restrictive. There could be to many
different layouts to keep it fair for all GO's. For example, there could be an
obstruction if limited to standing at the existing switchyard fence but if one
were to move a short distance away (i.e. corner of GO's building) then it
could be possible to see both ends of the tie line. This would also meet the
intent of the added language since it is now within line of sight. I
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
26
Organization
Yes or No
Question 1 Comment
recommend deleting "switchyard fence". Also, in order to account for a GO
not being able to dictate what happens inside a TO's switchyard, I
recommend adding "entry or" between "of" and "interconnection".
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and believes that using the fixed starting point of the
switchyard fence is best for eliminating confusion and any discretion on the part of a Generator Owner or an auditor. The SDT
intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that there is a
clear line of sight from any point along that length of line. In sum, the SDT has considered all relevant stakeholder comments
and is satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Wisconsin Electric; Wisconsin
Electric Power Co.; Wisconsin
Electric Power Marketing; Wisconsin
Energy Corp.
No
We strongly oppose the addition of the “clear” line of sight criteria to the
Applicability. The report of the GOTO Task Force, as well as prior draft
revisions to FAC-003, included a test based solely on circuit length, which is
sufficient in our view to assure that the BES is not at risk due to vegetation
issues on generator tie lines. The expansion to include short tie lines,
including those entirely on the Generator Owner’s property which may not
meet the line of sight qualifier, has no benefit to reliability. Rather, the
expanded applicability and the requirement for a formal vegetation
management program in these cases will consume resources for compliance
that are better used for actual reliability improvements.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. The SDT has considered all relevant stakeholder comments and is satisfied that we have determined the
appropriate language to address the reliability gap. No change made.
ExxonMobil Research and
Engineering
No
While it is clear that the SDT is attempting to include those facilities owned
by Generator Owners that travel long distances down right-of-ways, the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
27
Organization
Yes or No
Question 1 Comment
applicability section of FAC-003-X and FAC-003-3, as written, require
industrial complexes with cogeneration facilities to develop Transmission
Vegetation Management Programs for generator lead lines that are not
exposed to vegetation.
Industrial cogeneration location is typically chosen based on the availability
of fuel, need for steam, or availability of real estate. This can result with the
generation facilities (including the GSU transformer substation) being
located deep within the plant with long cable routes and multiple substation
connections between the GSU transformer substation and utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. Additionally, the routes of these generator lead lines
fundamentally differ in nature from a typical IPP’s generator lead line route.
Since they are located within the fence line of an industrial complex, the
routes rarely contain vegetation; are frequently travelled by plant
personnel; rarely run in straight lines (i.e. no single line of sight); and
frequently terminate at a facility located at the fence line of the industrial
complex where a transmission company takes ownership of the power lines
that leave the industrial complex. Furthermore, the use of the term
“generating station switchyard” may result in inconsistent enforcement of
the Transmission Vegetation Management Program Reliability Standard as
the use of the term implies there is only one substation located within a
Generator Owner’s complex. Typically, there are multiple substations that
connect an industrial complex’s generator lead-line to the utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. The two obvious interpretations for the “generating
station switchyard” are the substation that is directly connected to the
generator’s GSU, and the utility interconnection facility. The concerns
raised by NERC and FERC staff related generator owned transmission like
assets originate with those conductors that leave the Generator Owner’s
complex’s fence line and travel long distances down vacant right-of-ways,
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
28
Organization
Yes or No
Question 1 Comment
and, therefore, the applicability of those Reliability Standards that apply to
transmission facilities should start with the fence line.
Since the Bulk Electric System is contiguous, reliability concerns related to
the facilities between the GSU transformer substation and utility
interconnection facility are covered by those Reliability Standards that apply
to Generator Owners and Generator Operators. In order to account for the
different nature of industrial complex’s generation facilities, the SDT should
consider re-phrasing the applicability section of FAC-003-X and FAC-003-3 to
start counting the length of a generator lead line at the fence line of the
Generator Owner’s complex and not the generating station switchyard.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and for language in general within this qualifier, and it
believes that using the fixed starting point of the switchyard fence is best for eliminating confusion and any discretion on the
part of a Generator Owner or an auditor. In sum, the SDT has considered all relevant stakeholder comments and is satisfied that
we have determined the appropriate language to address the reliability gap, while exempting the most common lines with little
to no reliability risk for a vegetation issue. No change made.
City of Bartow, Florida; City of
Clewiston; Florida Municipal Power
Agency; Beaches Energy Services
Affirmative
Although we are supporting the change, the added applicability language
for GOs is ambiguous as to whether the qualifier "operated at 200 kV and
above and any lower voltage lines designated by the Regional Entity as
critical to the reliability of the electric system in the region" applies to both
portions of the applicability (e.g., 1) > 1 mile and 2) no clear line of sight), or
just to the second no clear line of sight applicability. FMPA assumes that the
qualifier applies to both. We recommend re-arranging of the sentence to
make this clearer by moving the qualifier to the beginning of the sentence
instead of the end of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the qualifier language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with 4.1.1 of FAC-003-X. No change
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
29
Organization
Yes or No
Question 1 Comment
Affirmative
AWEA supports the modifications in this standard, along with the other
standards modification under Project 2010-07, as a reasonable approach to
addressing the perceived reliability concerns with generator tie lines. We
believe a consistent approach for all Generator Owners and Generator
Operators that does not require registration as a Transmission Owner or
Transmission Operator is the most efficient and effective way to address
these concerns.
made.
American Wind Energy Association
Response: The SDT thanks you for your comment and support.
BrightSource Energy, Inc.
Affirmative
BrightSource would like to thank the SDT for the effort in developing the
standard. Our comment is more on providing more clarification. Depending
on the agreements between the TO and the GO, the Point of
Interconnection is not necessarily the point of change of ownership of the
transmission facilities. For example, the GO may own the portion of the
Gen-tie from the generating plant to the last tower outside the TO’s
substation and the TO owns the line drop from the last tower to the
termination equipment inside the TO substation. So to avoid confusion later
we suggest that we modify P4.3.1 by adding “to the point of change of
ownership or” as follows: “4.3.1. Generator Owner that owns an overhead
transmission line(s) that (1) extends greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to
the point of change of ownership or to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight1 from
the generating station switchyard fence to the point of interconnection with
a Transmission Owner’s Facility and is operated at 200 kV and above and
any lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.” Thank you.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
30
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comment and support. The SDT considered many different language choices for its
qualifying language, and it believes that “point of interconnection” is a clear phrase that will be understood and appropriately
applied. No change made.
Indiana Municipal Power Agency
Affirmative
IMPA supports the change, but would add the comment that the added
applicability language for GOs is ambiguous as to whether the qualifier
"operated at 200 kV and above and any lower voltage lines designated by
the Regional Entity as critical to the reliability of the electric system in the
region" applies to both portions of the applicability which are 1) > 1 mile
and 2) no clear line of sight), or just to the second portion for no clear line of
sight applicability. IMPA assumes that the qualifier applies to both. We
recommend reorganizing the sentence to make this more clear by moving
the qualifier to the beginning of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the exemption language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with the formatting in 4.1.1 of FAC003-X. No change made.
Nebraska Public Power District
Affirmative
NPPD joins the comments submitted by the MRO NSRF (Midwest Reliability
Organization - NERC Standards Review Forum)
Midwest Reliability Organization
Affirmative
Please refer to comments made by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review
Forum.
Lakeland Electric
Affirmative
See FMPA comments
Great River Energy
Affirmative
See NSRF comments
Bonneville Power Administration
Yes
BPA has no other comments or concerns at this time.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
31
Organization
NERC Compliance Policy
Yes or No
Yes
Question 1 Comment
Dominion offers the following comments on the Implementation Plan for
FAC-003-3:
1. The last paragraph on page 2 refers to FAC-003-3 Requirement 1.3. FAC003-3 does not appear to contain a Requirement 1.3; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
2. The 3rd paragraph on page 3 refers to FAC-003-3 Requirement 1.2. FAC003-3 does not appear to contain a Requirement 1.2; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
Response: Thank you for these suggestions. These references have been removed.
MRO NSRF
Yes
The NSRF agrees with the clarifying changes related to adding the phrase
“.....do not have a clear line of sight from the generating station switchyard
fence to the point of interconnection with a Transmission Owner’s
Facility.......”, however, have the following comment for SDT consideration:
o The Evidence Retention in FAC-003-3, Part C, Compliance, and
Section1.2implies that an entity is required to retain evidence for the time
period since the last audit. Since Generator Owners’ audit cycles are six (6)
years, and the following paragraph statesthat to show compliance for R1,
R2, R3, R5, R6 and R7is three calendar years unless directed by the CEA to
retain longer as part of an investigation, this section should be clarified to
require six years retention for applicable Generator Owners.
Response: Thank you for your comment. The SDT believes the data retention section is appropriate as written. No change made.
Edison Mission Marketing & Trading
Yes
Alabama Municipal Electric
Authority
Yes
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
32
Organization
Yes or No
American Electric Power
Yes
Public Service Enterprise Group
Yes
ACES Power Marketing
Yes
Essential Power, LLC
Yes
Ingleside Cogeneration LP
Yes
Question 1 Comment
END OF REPORT
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
33
Exhibit F
Analysis of how VRFs and VSLs Were Determined Using Commission Guidelines
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FAC001-1
R1
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO). Because the drafting
team made no changes to R1, the
team determined that any further
changes to R1’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors.. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
FAC001-1
R2
The VSLs for R2 are written in
accordance with NERC’s VSL
Guideline’s formatting
recommendations. The
requirement is not of the pass/fail
variety, so the VSL assignments
have been gradated based on
when the Generator Owner
documented and published the
Facility connection requirements.
As is recommended by NERC’s VSL
Guidelines, the drafting team
Because this is a new requirement,
there is no current level of
compliance with which the VSL
assignments can be compared.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. The
VSL assignments are consistent
with the requirement and the
degree of compliance can be
determined objectively and with
certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
The proposed text is clear, specific,
and does not contain general,
relative or subjective language
(and is not subject to the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. After
modifying “Transmission Owner”
to “responsibility entity”, the VSL
assignments are consistent with
the requirement and the degree of
compliance can be determined
objectively and with certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
identified a reasonable delay for
the Lower VSL and then used 10day increments to develop the
Moderate, High, and Severe VSLs.
FAC001-1
R3
For its proposed changes to VSLs
for FAC-001-1 R3, the drafting
team used the FERC-approved
VSLs (then FAC-001-0 R2) in 135
FERC ¶ 61,166 as a starting point.
The VSLs were already
appropriately gradated with
penalties based on the
recommendation for requirements
with parts that contribute equally
to the requirement, and removing
the second half of R3’s Severe VSL
simply avoids any double jeopardy
compliance issues, as indicated in
the Guideline 2 explanation.
possibility of multiple
interpretations), satisfying
Guideline 2b.
The drafting team’s slight
modification to the Severe VSL for
R3 does not signal a lower
compliance threshold than
previously existed.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team determined that
the second half of the Severe VSL
in R3 (“The responsible entity does
not have Facility connection
requirements”) could lead to
double jeopardy because of its
redundancy with the Severe VSLs
in R1 (“The Transmission Owner
did not develop Facility connection
requirements”) and R2 (“The
Generator Owner failed to
document and publish and
thereafter maintain Facility
connection requirements until
more than 80 days…”). Thus, the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
second half of the VSL for R3 has
been deleted.
With this change, the text is clear,
specific, and does not contain
general, relative or subjective
language (and is not subject to the
possibility of multiple
interpretations), satisfying
Guideline 2b.
FAC001-1
R4
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because, with this
posting, the drafting team made
no changes to R4 compared to the
FERC approved version (then R3),
the team determined that any
further changes to R4’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
VRFs for FAC-001-1:
The VRFs for FAC-001-1 were transferred from NERC’s VRF Matrix – which includes VRFs that have already been approved by FERC – to bring the
formatting of the standard up to date. A Medium VRF was added to new Requirement R2, which applies to Generator Owners, to match the
Medium VRF for the comparable Requirement R1, which applies to Transmission Owners.
Exhibit G
Record of Development of Proposed Reliability Standard
Project 2010-07
Generator Requirements at the Transmission
Interface
Related Files
Status:
FAC-001-1, FAC-003-3, PRC-004-2.1a, and PRC-005-1.1b and all associated
documents were adopted by NERC’s Board of Trustees (BOT) in February and May
2012. They are pending regulatory filing.
Purpose/Industry Need:
The proposed changes to the requirements and the addition of new requirements
will add significant clarity to Generator Owners and Generator Operators regarding
their reliability standard obligations at the interface with the interconnected grid.
Draft
Action
Dates
Results
FAC-003-x
Clean (143)| Redline to Last
Posted(144) | Redline to Last
Approved(145)
Implementation Plan
Clean(146) | Redline to Last
Posted(147)
Summary(162)
FAC-003-3
Clean(148) | Redline to Last
Posted(149) | Redline to Last
Approved(150)
Recirculation
Ballot
Info(161)
Implementation Plan
Clean(151) | Redline to Last
Posted(152)
Consideration of Comment Report
(FAC-003-3 and FAC-003-x - for
reference; from successive ballot that
took place March 9 - April 9, 2012)
Clean(153)
PRC-005-1.1b
Clean(154) | Redline to Last
Approved (155)
Vote>>
Ballot Results:
04/24/12
–
05/03/12
FAC-0033(163)
FAC-003x(164)
PRC-0051.1b(165)
Consideration
of Comments
Implementation Plan
Clean(156) | Redline to Last
Posted(157)
Consideration of Comment Report
(PRC-005-1.1b for reference; from
initial ballot that took place from
March 2 - April 16, 2012)
Clean(158)
Technical Justification Document
(for reference; updated from the
version posted in March 2012)
Clean(159) | Redline(160)
On January 20, 2012, Exelon submitted a Level 1 Appeal of the process, challenging the results of the
recirculation ballots of FAC-003-3 and FAC-003-X that concluded on Dec. 23, 2011. The NERC Vice
President of Standards and Training and then the Standards Committee's Executive Committee
reviewed the appeal and found for the appellant, determining that the modifications the SDT made to
the applicability of FAC-003-3 and FAC-003-x prior to the recirculation ballot were substantive.
Consequently the results of the recirculation ballots for FAC-003-3 and FAC-003-x have been declared
void. The SDT has made minor modifications to the standards and posted them for a parallel formal
comment period and successive ballot.
Exelon's Level 1 Appeal(141)
NERC Vice President of Standards and Training Response(142)
FAC-003-x
Clean(122)| Redline to Last
Posted(123)
FAC-003-3
Clean(124) | Redline to Last
Posted(125)
Implementation Plans
FAC-003-x
Clean(126)
FAC-003-3
Clean(127)
Supporting Materials:
Unofficial Comment Form
(Word)(128)
Standards Committee Executive
Committee 2/23/12 meeting minutes
Successive
Ballot
Info(135)
Info(136)
3/30/12
04/09/12
(closed)
Vote>>
Formal
Comment
Period
Submit
Comments>>
03/09/12
04/09/12
(closed)
Full Records:
FAC-003x(137)
FAC-0033(138)
Comments
Received(139)
Consideration of
Comments(140)
(directing that Recirculation Ballot
Results be voided and work remanded
to the SDT)(129)
Letter from SC Chairman to Project
2010-07 SDT Chair(130)
Technical Justification Document
(for reference; updated from the
version posted in December 2011)
Clean(131) | Redline(132)
Consideration of Comment Report
(for reference; updated from
successive ballot that took place
October 5-November 18, 2011)
Clean(133) | Redline(134)
PRC-005-1.1a
Clean(112) | Redline to Last
Approved(113)
Implementation Plan
Clean(114)
Supporting Materials
Unofficial Comment Form (Word)(115)
Initial Ballot
Updated
Info(116)
Info(117)
Vote>>
Formal
Comment
Period
Submit
Comments>>
Join Ballot
Pool>>
FAC-001-1
Clean(100) | Redline to Last
Approved(101)
Implementation Plan(102)
PRC-004-2.1a
Clean (103)| Redline to Last
Approved(104)
Implementation Plan(105)
Supporting Materials:
04/06/12
Info(118)
04/16/12
Full Record(119)
(closed)
03/02/12
04/16/12
(closed)
03/02/12
03/31/12
(closed)
Comments
Received(120)
Consideration of
Comments(121)
Technical Justification
Clean(106) | Redline(107)
Technical Justification for FAC-0011(108)
Sole-use Generator Interconnection
Facility: Diagram 1(109)
Sole-use Generator Interconnection
Facility: Diagram 2(110)
VRF and VSL Justification(111)
FAC-001-1 VRFs and VSLs
Clean(94) | Redline to last
approved(95)
Non-binding
Poll
Supporting Materials:
VRF and VSL Justification(96)
Info(98)
01/04/12
01/13/12
(closed)
Non-Binding
Poll Results(99)
Vote>>
FAC-001-1 Implementation Plan(97)
FAC-001-1
Clean (65)| Redline to Last Posted(66)
| Redline to Last Approved(67)
FAC-003-X
Clean (68)| Redline to Last Posted(69)
Summary(85)
FAC-003-3
Clean (70)| Redline to Last Posted(71)
Recirculation
Ballots
PRC-004-2.1
Clean(72) | Redline to Last Posted
(73)| Redline to Last Approved(74)
Info(84)
Implementation Plans
FAC-001-1
Clean(75)
FAC-003-3
Clean(76)
Vote>>
12/14/11
12/23/11
(closed)
Full Record
Reports:
FAC-001-1(86)
FAC-003-X(87)
FAC-003-3(88)
PRC-0042.1(89)
Full Record
Reports
(NOTE that the
results of the
recirculation
ballots of FAC003-3 and FAC003-x were
voided as a
FAC-003-X
Clean(77)
result of an
appeal, and a
successive ballot
of the two
standards was
conducted. The
appeal and
response are
posted on this
project page.)
PRC-004-2.1
Clean(78)
Supporting Materials:
Technical Justification
Clean (79)| Redline(80)
Technical Justification for FAC-0011(81)
FAC-001-1(90)
FAC-003-x(91)
FAC-003-3(92)
PRC-004-2.1(93)
Sole-use generator interconnection
Facility: Diagram 1(82)
Sole-use generator interconnection
Facility: Diagram 2(83)
FAC-001-1
Clean(32) | Redline to Last Posted
(33)| Redline to Last Approved(34)
Join Ballot
Pool
Info(54)
FAC-003-X
Clean (35)| Redline to Last Posted
(36)| Redline to Last Approved(37)
Join>>
FAC-003-3
Clean(38) | Redline to Last Posted
(39)
Initial Ballot
FAC-003-3 with revised VSLs based
on FAC-003-2 adopted by NERC BOT
(added 11/09/11)
Clean(40) | Redline to version of
FAC-003-3 posted 10/05/11(41)
Updated
Info(55)
Info(56)
10/05/11
11/04/11
(closed)
Summary(58)
11/09/11
11/18/11
(closed)
Vote>>
PRC-004-2.1
Clean(42) | Redline to Last
Approved(43)
Implementation Plans
FAC-001-1
Clean (44)| Redline(45)
FAC-003-3
Clean(46) | Redline(47)
FAC-003-X
Comment
Period
Info(57)
Submit
Comments>>
Full Record
Report:
FAC-001-1(59)
FAC-003-X(60)
FAC-003-3(61)
PRC-0042.1(62)
10/05/11
11/18/11
(closed)
Comments
Received(63)
Consideration of
Comments(64)
Clean(48) | Redline(49)
PRC-004-2
Clean(50)
Supporting Materials:
Technical Justification(51)
Technical Justification for FAC-0011(52)
Unofficial Comment Form (Word)(53)
FAC-001-1
Clean(18) | Redline to last
approved(19)
Implementation Plan(20)
FAC-003-3
Clean(21) | Redline to last approved
(22)
Implementation Plan(23)
Formal
Comment
Period
FAC-003-X
Info(29)
06/17/11
07/17/11
(closed)
Comments
Received(30)
Consideration of
Comments(31)
Comments
Received(16)
Summary
Consideration of
Comments(17)
Clean(24) | Redline to Project 2007-07 Submit
Comments>>
last balloted(25)
Implementation Plan(26)
Supporting Materials
Background Resource (White
Paper)(27)
Comment Form (Word) (28)
White Paper(12)
Informal
Comment
Period
Supporting Materials
Attachment 1 (13)| Attachment
2(14)
Info(15)
Submit
Comments>>
03/04/11
04/04/11
(closed)
SAR
Clean(3) | Redline(4)
Generator Requirements at the
Transmission Interface (GOTO)
Comment
Period
SAR(5)
Submit
Comments>>
Redline Standard Changes(6)
Info(9)
02/12/10
03/15/10
(closed)
Supporting Materials
GOTO Final Report(7)
Comment Form (Word)(8)
Drafting Team Nominations Open
Nomination Form (Word)(1)
Submit
02/12/10
Nomination>>
03/01/10
Info(2)
(closed)
Comments
Received(10)
Consideration of
comments(11)
Unofficial Nomination Form for the Drafting Team for Generator Requirements at
the Transmission Interface — Project 2010-07
Please DO NOT use this form. Please use the electronic nomination form located at the link
below by March 1, 2010. If you have any questions, please contact David Taylor at
david.taylor@nerc.net or by telephone at 609-651-5089.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
By submitting the following information you are indicating your willingness and agreement
to actively participate in the Drafting Team meetings if appointed to the Drafting Team by
the Standards Committee. This means that if you are appointed to the DT you are expected
to attend all (or at least the vast majority) of the face-to-face DT meetings as well as
participate in all the DT meetings held via conference calls and failure to do so shall result in
your removal from the DT.
Name:
Organization:
Address:
Telephone:
E-mail:
Project 2010-07 Generator Requirements at the Transmission Interface: The purpose of
the SAR and associated definition and standard changes is to provide greater clarity to the
requirements associated with Generator Interconnection Facilities. This includes adding/modifying
some definitions, and adding/modifying some requirements to capture responsibilities for owning
and operating the Generator Interconnection Facility, and to add requirements where necessary
that should be applicable to Generator Operators regardless of the interconnection configuration.
Please briefly describe your experience and qualifications directly related to the issues to be
addressed by the Generator Requirements at the Transmission Interface Drafting Team. We are
seeking a cross section of the industry to participate on the team, but in particular are seeking
individuals who participated in the Ad Hoc Group for Generator Requirements at the Transmission
Interface, and individuals who work for entities registered as generator owners, generator
operators, and others with expertise in those activities associated with the new/modified
requirements proposed with the SAR.
Experience in developing standards inside or outside (i.e., IEEE, NAESB, ANSI, etc.) of the NERC
process is beneficial, but is not required, and should be highlighted in the information submitted if
applicable.
Are you currently a member of any NERC or Regional Entity SAR or standard drafting
team? If yes, please list each team here.
No
Yes:
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
Unofficial Nomination Form for Project 2010-07 — Generator Requirements at the Transmission
Interface
Have you previously worked on any NERC or Regional Entity SAR or standard drafting
teams? If yes, please list them here.
No
Yes:
Please identify the NERC Reliability Region(s) in which your company operates and for
which you are able to represent your company’s position relative to the applicable issues
while serving on the SAR drafting team:
ERCOT
MRO
RFC
SPP
FRCC
NPCC
SERC
WEC
Not Applicable or None of the Above
Please identify the Industry Segment(s) for which you are able to represent on behalf of
your company while serving on the SAR drafting team:
— Transmission Owners
— RTOs and ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
Federal, State, and Provincial Regulatory or other Government Entities
2
Unofficial Nomination Form for Project 2010-07 — Generator Requirements at the Transmission
Interface
Regional Reliability Organizations and Regional Entities
Not applicable
Which of the following Functional Entities 1 do you have expertise or responsibilities for
which you are able to represent on behalf of your company while serving on the SAR
drafting team:
Balancing Authority
Planning Coordinator
Compliance Enforcement Authority
Transmission Operator
Distribution Provider
Transmission Owner
Generator Operator
Transmission Planner
Generator Owner
Transmission Service Provider
Interchange Authority
Purchasing-selling Entity
Load-serving Entity
Resource Planner
Market Operator
Reliability Coordinator
Please provide the names and contact information for two references who could attest
to your technical qualifications and your ability to work well in a group which you give
us permission to contact in the event it is deemed necessary to do so.
Name and
Title:
Office
Telephone:
Organization:
E-mail:
Name and
Title:
Office
Telephone:
Organization:
E-mail:
1
These functions are defined in the NERC Functional Model, which is available on the NERC Web site.
3
Standards Announcement
Standards Authorization Request (SAR) Comment and Drafting Team
Nomination Periods Open
Project 2010-07: Generator Requirements at the Transmission Interface
Now available at: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Nominations for Drafting Team (through March 1, 2010)
The Standards Committee is seeking industry experts to serve on the Generator Requirements at the
Transmission Interface Drafting Team (see project background below).
If you are interested in serving on this drafting team, please complete this electronic nomination form by
March 1, 2010.
Comment Period (through March 15, 2010)
The Standards Committee has posted a proposed SAR for a 30-day comment period ending on March 15,
2010. Also posted are proposed revisions to existing standards and a copy of the final report published by the
Ad Hoc Group for Generator Requirements at the Transmission Interface.
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at Lauren.Koller@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page (see project background below).
Project Background
On January 14, 2008, the NERC Board of Trustees Compliance Committee upheld the Western Electricity
Coordinating Council’s (WECC’s) determination to register the New Harquahala Generating Company
(Harquahala) as a Transmission Owner and Transmission Operator. This determination is based on
Harquahala’s 26-mile 500 kV interconnection facilities that connect the plant with the Hassayampa
transmission substation. This decision was upheld by FERC and caused concern for Generator Owners and
Generator Operators who owned only transmission “tie-line” facilities used to connect their generating facilities
to a transmission substation.
In response to concerns from members of the generator segment regarding this decision, NERC conducted a
survey in the Fall of 2008 to define and collect recommendations for resolving stakeholders concerns, and to
review and highlight those Transmission Owner and Transmission Operator requirements that should be
considered for generic applicability for Generator Owners and Generator Operators for their tie-line facilities.
Based on the survey recommendations, NERC formed a group of industry representatives to “Evaluate existing
NERC Reliability Standard requirements and develop a recommendation and possible standards authorization
request to address gaps in reliability for interconnection facilities of the Generator Owner and expectations for
the Generator Operator in operating those facilities. Propose strategies to address or resolve other related issues
as appropriate.” In November 2009, the group published report of its conclusions and recommendations.
This project is the result of those recommendations, which include proposed definitions and changes to existing
standards to add clarity to Generator Owners and Generator Operators regarding their reliability standard
obligations at the interface with the interconnected grid.
Project page: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at shaun.streeter@nerc.net or at 609.452.8060.
Standard Authorization Request Form
Title of Proposed Standard
Requirements
Various Standards Containing GO/GOP and TO/TOP
Request Date
January 15, 2010
SC Approval Date
January 20, 2010
Revised Date
November 30, 2010
SAR Requester Information
SAR Type (Check a box for each one
that applies.)
Name
Ad Hoc Group for Generator Requirements at the
Transmission Interface
New Standard
Primary Contact
Scott Helyer
Revision to existing Standards
Telephone
Withdrawal of existing Standard
817-462-1512
Fax
E-mail
shelyer@tnsk.com
Urgent Action
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Authorization Request Form
Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
The proposed changes to the requirements and the addition of new requirements will add significant
clarity to Generator Owners and Generator Operators regarding their reliability standard obligations at the
interface with the interconnected grid.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
Significant industry concern exists regarding the application of Transmission Owner and Transmission
Operator requirements, and more generally, to the registration of Generator Owners and Generator
Operators as Transmission Owners and Transmission Operators, based on the facilities that connect the
generators to the interconnected grid. The final report of the Ad Hoc Group for Generator Requirements
at the Transmission Interface evaluated the issue and proposes a number of changes that adds much
needed clarity on the requirements for Generator Interconnection Facilities. Absent these revisions and
additional requirements, Generator Owners and Generator Operators are subject to what some believe to
be inappropriate registration as Transmission Owners and Transmission Operators to ensure coverage
for certain reliability requirements. The modifications and additions recommended wholly and directly
address the requirements for Generator Owners and Generator Operators regarding its Generator
Interconnection Facilities, and add particular focus on the operation of the interface point at which
operating responsibility shifts from the Generator Operator to the Transmission Operator.
The proposal also modifies certain of NERC's existing glossary terms and adds new terms to support the
standards modifications.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
32 NERC Reliability Standards contain language regarding generators or generating facilities for which
greater clarity regarding its Generator Interconnection Facilities would ensure no reliability gap exists
12 requirements in FAC-003-1 - Transmission Vegetation Management should have their applicability
expanded to include Generator Owners.
2 NERC Reliability Standards should have their applicability expanded to include Generator Operators to
address general reliability gaps not attributable to their Generator Interconnection Facilities.
8 new Reliability Standard Requirements should be added to ensure the responsibilities for owning and
operating the Generator Interconnection Facility are clear, and to address certain requirements that
should apply to all generators regardless of interconnection configuration.
New NERC Glossary definitions are needed for Generator Interconnection Facility and Generator
Interconnection Operational Interface, as well as modifications to Vegetation Inspection, Right-of-Way,
Generator Owner, Generator Operator, and Transmission
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
Refer to Final Report of the Ad hoc Group for Generator Requirements at the Transmission Interface.
Revisions to the latest versions of the following standards are included in the report and redline standard
changes are included to accompany this SAR:
BAL-005
CIP-002
EOP-001, -003, -004, -008
FAC-001, -003, -008, -009
SAR–2
Standards Authorization Request Form
IRO-005
MOD-010, -012
PER-001, -002
PRC-001, -004, -005
TOP-001, -002, -003, -004, -008
VAR-001, -002
SAR–3
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–4
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market
Interface Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR–5
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–6
Standard Authorization Request Form
Title of Proposed Standard
Requirements
Various Standards Containing GO/GOP and TO/TOP
Request Date
January 15, 2010
SC Approval Date
January 20, 2010
Revised Date
November 30, 2010
SAR Requester Information
SAR Type (Check a box for each one
that applies.)
Name
Ad Hoc Group for Generator Requirements at the
Transmission Interface
New Standard
Primary Contact
Scott Helyer
Revision to existing Standards
Telephone
Withdrawal of existing Standard
817-462-1512
Fax
E-mail
shelyer@tnsk.com
Urgent Action
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Authorization Request Form
Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
The proposed changes to the requirements and the addition of new requirements will add significant
clarity to Generator Owners and Generator Operators regarding their reliability standard obligations at the
interface with the interconnected grid.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
Significant industry concern exists regarding the application of Transmission Owner and Transmission
Operator requirements, and more generally, to the registration of Generator Owners and Generator
Operators as Transmission Owners and Transmission Operators, based on the facilities that connect the
generators to the interconnected grid. The final report of the Ad Hoc Group for Generator Requirements
at the Transmission Interface evaluated the issue and proposes a number of changes that adds much
needed clarity on the requirements for Generator Interconnection Facilities. Absent these revisions and
additional requirements, Generator Owners and Generator Operators are subject to what some believe to
be inappropriate registration as Transmission Owners and Transmission Operators to ensure coverage
for certain reliability requirements. The modifications and additions recommended wholly and directly
address the requirements for Generator Owners and Generator Operators regarding its Generator
Interconnection Facilities, and add particular focus on the operation of the interface point at which
operating responsibility shifts from the Generator Operator to the Transmission Operator.
The proposal also modifies certain of NERC's existing glossary terms and adds new terms to support the
standards modifications.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
32 NERC Reliability Standards contain language regarding generators or generating facilities for which
greater clarity regarding its Generator Interconnection Facilities would ensure no reliability gap exists
12 requirements in FAC-003-1 - Transmission Vegetation Management should have their applicability
expanded to include Generator Owners.
2 NERC Reliability Standards should have their applicability expanded to include Generator Operators to
address general reliability gaps not attributable to their Generator Interconnection Facilities.
8 new Reliability Standard Requirements should be added to ensure the responsibilities for owning and
operating the Generator Interconnection Facility are clear, and to address certain requirements that
should apply to all generators regardless of interconnection configuration.
New NERC Glossary definitions are needed for Generator Interconnection Facility and Generator
Interconnection Operational Interface, as well as modifications to Vegetation Inspection, Right-of-Way,
Generator Owner, Generator Operator, and Transmission
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
Refer to Final Report of the Ad hoc Group for Generator Requirements at the Transmission Interface.
Revisions to the latest versions of the following standards are included in the report and redline standard
changes are included to accompany this SAR:
BAL-005
CIP-002
EOP-001, -003, -004, -008
FAC-001, -003, -008, -009
SAR–2
Standards Authorization Request Form
IRO-005
MOD-010, -012
PER-001, -002
PRC-001, -004, -005
TOP-001, -002, -003, -004, -008
VAR-001, -002
SAR–3
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–4
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market
Interface Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR–5
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–6
Standard Authorization Request Form
Title of Proposed Standard: Various Standards Containing GO/GOP and TO/TOP
Requirements
Request Date:
January 15, 2010
SC Approval Date:
January 20, 2010
SAR Type (Check a box for each one that
applies.)
SAR Requester Information
Name: Ad Hoc Group for Generator
Requirements at the Transmission Interface
New Standard
Primary Contact: Scott Helyer
Revision to existing Standards
Telephone: 817-462-1512
Withdrawal of existing Standard
Fax:
E-mail: shelyer@tnsk.com
Urgent Action
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com
Standards Authorization Request Form
Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
The proposed changes to the requirements and the addition of new requirements will add
significant clarity to Generator Owners and Generator Operators regarding their reliability
standard obligations at the interface with the interconnected grid.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
Significant industry concern exists regarding the application of Transmission Owner and
Transmission Operator requirements, and more generally, to the registration of Generator
Owners and Generator Operators as Transmission Owners and Transmission Operators,
based on the facilities that connect the generators to the interconnected grid. The final
report of the Ad Hoc Group for Generator Requirements at the Transmission Interface
evaluated the issue and proposes a number of changes that adds much needed clarity on
the requirements for Generator Interconnection Facilities. Absent these revisions and
additional requirements, Generator Owners and Generator Operators are subject to what
some believe to be inappropriate registration as Transmission Owners and Transmission
Operators to ensure coverage for certain reliability requirements. The modifications and
additions recommended wholly and directly address the requirements for Generator Owners
and Generator Operators regarding its Generator Interconnection Facilities, and add
particular focus on the operation of the interface point at which operating responsibility
shifts from the Generator Operator to the Transmission Operator.
The proposal also modifies certain of NERC's existing glossary terms and adds new terms to
support the standards modifications.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
32 NERC Reliability Standards contain language regarding generators or generating facilities
for which greater clarity regarding its Generator Interconnection Facilities would ensure no
reliability gap exists
12 requirements in FAC-003-1 - Transmission Vegetation Management should have their
applicability expanded to include Generator Owners.
2 NERC Reliability Standards should have their applicability expanded to include Generator
Operators to address general reliability gaps not attributable to their Generator
Interconnection Facilities.
8 new Reliability Standard Requirements should be added to ensure the responsibilities for
owning and operating the Generator Interconnection Facility are clear, and to address
certain requirements that should apply to all generators regardless of interconnection
configuration.
New NERC Glossary definitions are needed for Generator Interconnection Facility and
Generator Interconnection Operational Interface, as well as modifications to Vegetation
Inspection, Right-of-Way, Generator Owner, Generator Operator, and Transmission
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
Refer to Final Report of the Ad hoc Group for Generator Requirements at the Transmission
Interface.
SAR–2
Standards Authorization Request Form
Revisions to the latest versions of the following standards are included in the report and
redline standard changes are included to accompany this SAR:
BAL-005
CIP-002
EOP-001, -003, -004, -008
FAC-001, -003, -008, -009
IRO-005
MOD-010, -012
PER-001, -002
PRC-001, -004, -005
TOP-001, -002, -003, -004, -008
VAR-001, -002
SAR–3
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–4
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR–5
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–6
Standard BAL-005-0.1b — Automatic Generation Control
A.
B.
Introduction
1.
Title:
Automatic Generation Control
2.
Number:
BAL-005-0.1b
3.
Purpose:
This standard establishes requirements for Balancing Authority Automatic Generation Control
(AGC) necessary to calculate Area Control Error (ACE) and to routinely deploy the
Regulating Reserve. The standard also ensures that all facilities and load electrically
synchronized to the Interconnection are included within the metered boundary of a Balancing
Area so that balancing of resources and demand can be achieved.
4.
Applicability:
4.1. Balancing Authorities
4.2. Generator Operators
4.3. Transmission Operators
4.4. Load Serving Entities
5.
Effective Date:
May 13, 2009TBD
Requirements
R1. All generation, transmission, and load operating within an Interconnection must be included
within the metered boundaries of a Balancing Authority Area.
R1.1. Each Generator Operator with generation facilities, including its Generator
Interconnection Facility, operating in an Interconnection shall ensure that those
generation facilities are included within the metered boundaries of a Balancing
Authority Area.
R1.2. Each Transmission Operator with transmission facilities operating in an
Interconnection shall ensure that those transmission facilities are included within the
metered boundaries of a Balancing Authority Area.
R1.3. Each Load-Serving Entity with load operating in an Interconnection shall ensure that
those loads are included within the metered boundaries of a Balancing Authority Area.
R2. Each Balancing Authority shall maintain Regulating Reserve that can be controlled by AGC to
meet the Control Performance Standard.
R3. A Balancing Authority providing Regulation Service shall ensure that adequate metering,
communications, and control equipment are employed to prevent such service from becoming
a Burden on the Interconnection or other Balancing Authority Areas.
R4. A Balancing Authority providing Regulation Service shall notify the Host Balancing
Authority for whom it is controlling if it is unable to provide the service, as well as any
Intermediate Balancing Authorities.
R5. A Balancing Authority receiving Regulation Service shall ensure that backup plans are in
place to provide replacement Regulation Service should the supplying Balancing Authority no
longer be able to provide this service.
R6. The Balancing Authority’s AGC shall compare total Net Actual Interchange to total Net
Scheduled Interchange plus Frequency Bias obligation to determine the Balancing Authority’s
ACE. Single Balancing Authorities operating asynchronously may employ alternative ACE
calculations such as (but not limited to) flat frequency control. If a Balancing Authority is
unable to calculate ACE for more than 30 minutes it shall notify its Reliability Coordinator.
Adopted by NERC Board of Trustees: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 1 o
Standard BAL-005-0.1b — Automatic Generation Control
R7. The Balancing Authority shall operate AGC continuously unless such operation adversely
impacts the reliability of the Interconnection. If AGC has become inoperative, the Balancing
Authority shall use manual control to adjust generation to maintain the Net Scheduled
Interchange.
R8. The Balancing Authority shall ensure that data acquisition for and calculation of ACE occur at
least every six seconds.
R8.1. Each Balancing Authority shall provide redundant and independent frequency metering
equipment that shall automatically activate upon detection of failure of the primary
source. This overall installation shall provide a minimum availability of 99.95%.
R9. The Balancing Authority shall include all Interchange Schedules with Adjacent Balancing
Authorities in the calculation of Net Scheduled Interchange for the ACE equation.
R9.1. Balancing Authorities with a high voltage direct current (HVDC) link to another
Balancing Authority connected asynchronously to their Interconnection may choose to
omit the Interchange Schedule related to the HVDC link from the ACE equation if it is
modeled as internal generation or load.
R10. The Balancing Authority shall include all Dynamic Schedules in the calculation of Net
Scheduled Interchange for the ACE equation.
R11. Balancing Authorities shall include the effect of ramp rates, which shall be identical and
agreed to between affected Balancing Authorities, in the Scheduled Interchange values to
calculate ACE.
R12. Each Balancing Authority shall include all Tie Line flows with Adjacent Balancing Authority
Areas in the ACE calculation.
R12.1. Balancing Authorities that share a tie shall ensure Tie Line MW metering is
telemetered to both control centers, and emanates from a common, agreed-upon source
using common primary metering equipment. Balancing Authorities shall ensure that
megawatt-hour data is telemetered or reported at the end of each hour.
R12.2. Balancing Authorities shall ensure the power flow and ACE signals that are utilized for
calculating Balancing Authority performance or that are transmitted for Regulation
Service are not filtered prior to transmission, except for the Anti-aliasing Filters of Tie
Lines.
R12.3. Balancing Authorities shall install common metering equipment where Dynamic
Schedules or Pseudo-Ties are implemented between two or more Balancing
Authorities to deliver the output of Jointly Owned Units or to serve remote load.
R13. Each Balancing Authority shall perform hourly error checks using Tie Line megawatt-hour
meters with common time synchronization to determine the accuracy of its control equipment.
The Balancing Authority shall adjust the component (e.g., Tie Line meter) of ACE that is in
error (if known) or use the interchange meter error (IME) term of the ACE equation to
compensate for any equipment error until repairs can be made.
R14. The Balancing Authority shall provide its operating personnel with sufficient instrumentation
and data recording equipment to facilitate monitoring of control performance, generation
response, and after-the-fact analysis of area performance. As a minimum, the Balancing
Authority shall provide its operating personnel with real-time values for ACE, Interconnection
frequency and Net Actual Interchange with each Adjacent Balancing Authority Area.
R15. The Balancing Authority shall provide adequate and reliable backup power supplies and shall
periodically test these supplies at the Balancing Authority’s control center and other critical
locations to ensure continuous operation of AGC and vital data recording equipment during
loss of the normal power supply.
Adopted by NERC Board of Trustees: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 2 o
Standard BAL-005-0.1b — Automatic Generation Control
R16. The Balancing Authority shall sample data at least at the same periodicity with which ACE is
calculated. The Balancing Authority shall flag missing or bad data for operator display and
archival purposes. The Balancing Authority shall collect coincident data to the greatest
practical extent, i.e., ACE, Interconnection frequency, Net Actual Interchange, and other data
shall all be sampled at the same time.
R17. Each Balancing Authority shall at least annually check and calibrate its time error and
frequency devices against a common reference. The Balancing Authority shall adhere to the
minimum values for measuring devices as listed below:
Device
Digital frequency transducer
MW, MVAR, and voltage transducer
Remote terminal unit
Potential transformer
Current transformer
C.
Accuracy
0.001 Hz
0.25 % of full scale
0.25 % of full scale
0.30 % of full scale
0.50 % of full scale
Measures
Not specified.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
Balancing Authorities shall be prepared to supply data to NERC in the format defined
below:
1.2.
1.1.1.
Within one week upon request, Balancing Authorities shall provide NERC or
the Regional Reliability Organization CPS source data in daily CSV files with
time stamped one minute averages of: 1) ACE and 2) Frequency Error.
1.1.2.
Within one week upon request, Balancing Authorities shall provide NERC or
the Regional Reliability Organization DCS source data in CSV files with time
stamped scan rate values for: 1) ACE and 2) Frequency Error for a time
period of two minutes prior to thirty minutes after the identified Disturbance.
Compliance Monitoring Period and Reset Timeframe
Not specified.
1.3.
1.4.
Data Retention
1.3.1.
Each Balancing Authority shall retain its ACE, actual frequency, Scheduled
Frequency, Net Actual Interchange, Net Scheduled Interchange, Tie Line
meter error correction and Frequency Bias Setting data in digital format at the
same scan rate at which the data is collected for at least one year.
1.3.2.
Each Balancing Authority or Reserve Sharing Group shall retain
documentation of the magnitude of each Reportable Disturbance as well as
the ACE charts and/or samples used to calculate Balancing Authority or
Reserve Sharing Group disturbance recovery values. The data shall be
retained for one year following the reporting quarter for which the data was
recorded.
Additional Compliance Information
Not specified.
Adopted by NERC Board of Trustees: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 3 o
Standard BAL-005-0.1b — Automatic Generation Control
2.
Levels of Non-Compliance
Not specified.
E.
Regional Differences
None identified.
F.
Associated Documents
1.
Appendix 1 – Interpretation of Requirement R17 (February 12, 2008).
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
0a
December 19,
2007
Added Appendix 1 – Interpretation of R17
approved by BOT on May 2, 2007
Addition
0a
January 16,
2008
Section F: added “1.”; changed hyphen to
“en dash.” Changed font style for
“Appendix 1” to Arial.
Errata
0b
February 12,
2008
Replaced Appendix 1 – Interpretation of
R17 approved by BOT on February 12,
2008.
Replacement
0.1b
October 29,
2008
BOT approved errata changes; updated
version number to “0.1b”
Errata
0.1b
May 13, 2009
FERC approved – Updated Effective Date
and Footer
Addition
TBD
Modified R1.1 to include its Generator
Interconnection Facility
Addition
1b
Adopted by NERC Board of Trustees: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 4 o
Standard BAL-005-0.1b — Automatic Generation Control
Appendix 1
Request: PGE requests clarification regarding the measuring devices for which the requirement applies,
specifically clarification if the requirement applies to the following measuring devices:
Only equipment within the operations control room
Only equipment that provides values used to calculate AGC ACE
Only equipment that provides values to its SCADA system
Only equipment owned or operated by the BA
Only to new or replacement equipment
To all equipment that a BA owns or operates
BAL-005-1
R17. Each Balancing Authority shall at least annually check and calibrate its time error and frequency
devices against a common reference. The Balancing Authority shall adhere to the minimum values for
measuring devices as listed below:
Device
Accuracy
Digital frequency transducer
≤ 0.001 Hz
MW, MVAR, and voltage transducer
≤ 0.25% of full scale
Remote terminal unit
≤ 0.25% of full scale
Potential transformer
≤ 0.30% of full scale
Current transformer
≤ 0.50% of full scale
Existing Interpretation Approved by Board of Trustees May 2, 2007
BAL-005-0, Requirement 17 requires that the Balancing Authority check and calibrate its control room
time error and frequency devices against a common reference at least annually. The requirement to
“annually check and calibrate” does not address any devices outside of the operations control room.
The table represents the design accuracy of the listed devices. There is no requirement within the standard
to “annually check and calibrate” the devices listed in the table, unless they are included in the control
center time error and frequency devices.
Interpretation:
As noted in the existing interpretation, BAL-005-1 Requirement 17 applies only to the time error and
frequency devices that provide, or in the case of back-up equipment may provide, input into the reporting
or compliance ACE equation or provide real-time time error or frequency information to the system
operator. Frequency inputs from other sources that are for reference only are excluded. The time error and
frequency measurement devices may not necessarily be located in the system operations control room or
owned by the Balancing Authority; however the Balancing Authority has the responsibility for the
accuracy of the frequency and time error measurement devices. No other devices are included in R 17.
The other devices listed in the table at the end of R17 are for reference only and do not have any
mandatory calibration or accuracy requirements.
New or replacement equipment that provides the same functions noted above requires the same
calibrations. Some devices used for time error and frequency measurement cannot be calibrated as such.
In this case, these devices should be cross-checked against other properly calibrated equipment and
replaced if the devices do not meet the required level of accuracy.
Adopted by NERC Board of Trustees: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 5 o
Standard CIP–002–X1 — Cyber Security — Critical Cyber Asset Identification
A. Introduction
1.
Title:
Cyber Security — Critical Cyber Asset Identification
2.
Number:
CIP-002-X1
3.
Purpose:
NERC Standards CIP-002 through CIP-009 provide a cyber security framework
for the identification and protection of Critical Cyber Assets to support reliable operation of the
Bulk Electric System.
These standards recognize the differing roles of each entity in the operation of the Bulk Electric
System, the criticality and vulnerability of the assets needed to manage Bulk Electric System
reliability, and the risks to which they are exposed. Responsible Entities should interpret and
apply Standards CIP-002 through CIP-009 using reasonable business judgment.
Business and operational demands for managing and maintaining a reliable Bulk Electric
System increasingly rely on Cyber Assets supporting critical reliability functions and processes
to communicate with each other, across functions and organizations, for services and data. This
results in increased risks to these Cyber Assets.
Standard CIP-002 requires the identification and documentation of the Critical Cyber Assets
associated with the Critical Assets that support the reliable operation of the Bulk Electric
System. These Critical Assets are to be identified through the application of a risk-based
assessment.
4.
Applicability:
4.1. Within the text of Standard CIP-002, “Responsible Entity” shall mean:
4.1.1
Reliability Coordinator.
4.1.2
Balancing Authority.
4.1.3
Interchange Authority.
4.1.4
Transmission Service Provider.
4.1.5
Transmission Owner.
4.1.6
Transmission Operator.
4.1.7
Generator Owner.
4.1.8
Generator Operator.
4.1.9
Load Serving Entity.
4.1.10 NERC.
4.1.11 Regional Reliability Organizations.
4.2. The following are exempt from Standard CIP-002:
5.
4.2.1
Facilities regulated by the U.S. Nuclear Regulatory Commission or the Canadian
Nuclear Safety Commission.
4.2.2
Cyber Assets associated with communication networks and data communication
links between discrete Electronic Security Perimeters.
Effective Date:
June 1, 2006TBD
Adopted by Board of Trustees: May 2, 2006TBD
Effective Date: June 1, 2006TBD
Page 1 of 4
Standard CIP–002–X1 — Cyber Security — Critical Cyber Asset Identification
B. Requirements
The Responsible Entity shall comply with the following requirements of Standard CIP-002:
R1.
Critical Asset Identification Method — The Responsible Entity shall identify and document a
risk-based assessment methodology to use to identify its Critical Assets.
R1.1.
The Responsible Entity shall maintain documentation describing its risk-based
assessment methodology that includes procedures and evaluation criteria.
R1.2.
The risk-based assessment shall consider the following assets:
R1.2.1. Control centers and backup control centers performing the functions of the
entities listed in the Applicability section of this standard.
R1.2.2. Transmission substations that support the reliable operation of the Bulk
Electric System.
R1.2.3. Generation resources, including the Generator Interconnection Facility, that
support the reliable operation of the Bulk Electric System.
R1.2.4. Systems and facilities critical to system restoration, including blackstart
generators and their attendant Generator Interconnection Facility, and
substations in the electrical path of transmission lines used for initial system
restoration.
R1.2.5. Systems and facilities critical to automatic load shedding under a common
control system capable of shedding 300 MW or more.
R1.2.6. Special Protection Systems that support the reliable operation of the Bulk
Electric System.
R1.2.7. Any additional assets that support the reliable operation of the Bulk Electric
System that the Responsible Entity deems appropriate to include in its
assessment.
R2.
Critical Asset Identification — The Responsible Entity shall develop a list of its identified
Critical Assets determined through an annual application of the risk-based assessment
methodology required in R1. The Responsible Entity shall review this list at least annually,
and update it as necessary.
R3.
Critical Cyber Asset Identification — Using the list of Critical Assets developed pursuant to
Requirement R2, the Responsible Entity shall develop a list of associated Critical Cyber Assets
essential to the operation of the Critical Asset. Examples at control centers and backup control
centers include systems and facilities at master and remote sites that provide monitoring and
control, automatic generation control, real-time power system modeling, and real-time interutility data exchange. The Responsible Entity shall review this list at least annually, and
update it as necessary. For the purpose of Standard CIP-002, Critical Cyber Assets are further
qualified to be those having at least one of the following characteristics:
R4.
R3.1.
The Cyber Asset uses a routable protocol to communicate outside the Electronic
Security Perimeter; or,
R3.2.
The Cyber Asset uses a routable protocol within a control center; or,
R3.3.
The Cyber Asset is dial-up accessible.
Annual Approval — A senior manager or delegate(s) shall approve annually the list of Critical
Assets and the list of Critical Cyber Assets. Based on Requirements R1, R2, and R3 the
Responsible Entity may determine that it has no Critical Assets or Critical Cyber Assets. The
Responsible Entity shall keep a signed and dated record of the senior manager or delegate(s)’s
Adopted by Board of Trustees: May 2, 2006TBD
Effective Date: June 1, 2006TBD
Page 2 of 4
Standard CIP–002–X1 — Cyber Security — Critical Cyber Asset Identification
approval of the list of Critical Assets and the list of Critical Cyber Assets (even if such lists are
null.)
C. Measures
The following measures will be used to demonstrate compliance with the requirements of Standard
CIP-002:
M1.
The risk-based assessment methodology documentation as specified in Requirement R1.
M2.
The list of Critical Assets as specified in Requirement R2.
M3.
The list of Critical Cyber Assets as specified in Requirement R3.
M4.
The records of annual approvals as specified in Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
1.1.1
Regional Reliability Organizations for Responsible Entities.
1.1.2
NERC for Regional Reliability Organization.
1.1.3
Third-party monitor without vested interest in the outcome for NERC.
1.2. Compliance Monitoring Period and Reset Time Frame
Annually.
1.3. Data Retention
1.3.1
The Responsible Entity shall keep documentation required by Standard CIP-002
from the previous full calendar year
1.3.2
The compliance monitor shall keep audit records for three calendar years.
1.4. Additional Compliance Information
1.4.1
Responsible Entities shall demonstrate compliance through self-certification or
audit, as determined by the Compliance Monitor.
2. Levels of Non-Compliance
2.1 Level 1: The risk assessment has not been performed annually.
2.2 Level 2: The list of Critical Assets or Critical Cyber Assets exist, but has not been
approved or reviewed in the last calendar year.
2.3 Level 3: The list of Critical Assets or Critical Cyber Assets does not exist.
2.4 Level 4: The lists of Critical Assets and Critical Cyber Assets do not exist.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
1
01/16/06
R3.2 — Change “Control Center” to
“control center”
03/24/06
X
TBD
Modified R1.2.3 to include the Generator
Interconnection Facility and R1.2.4 to
Addition
Adopted by Board of Trustees: May 2, 2006TBD
Effective Date: June 1, 2006TBD
Page 3 of 4
Standard CIP–002–X1 — Cyber Security — Critical Cyber Asset Identification
include a Generator Interconnection Facility
Adopted by Board of Trustees: May 2, 2006TBD
Effective Date: June 1, 2006TBD
Page 4 of 4
Standard EOP-001-X0 — Emergency Operations Planning
A. Introduction
1.
Title:
Emergency Operations Planning
2.
Number:
EOP-001-X0
3.
Purpose:
Each Transmission Operator and Balancing Authority needs to develop,
maintain, and implement a set of plans to mitigate operating emergencies. These plans need to
be coordinated with other Transmission Operators and Balancing Authorities, and the
Reliability Coordinator.
4.
Applicability
4.1. Balancing Authorities.
4.2. Transmission Operators.
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
Balancing Authorities shall have operating agreements with adjacent Balancing Authorities
that shall, at a minimum, contain provisions for emergency assistance, including provisions to
obtain emergency assistance from remote Balancing Authorities.
R2.
The Transmission Operator shall have an emergency load reduction plan for all identified
IROLs. The plan shall include the details on how the Transmission Operator will implement
load reduction in sufficient amount and time to mitigate the IROL violation before system
separation or collapse would occur. The load reduction plan must be capable of being
implemented within 30 minutes.
R3.
Each Transmission Operator and Balancing Authority shall:
R4.
R5.
R3.1.
Develop, maintain, and implement a set of plans to mitigate operating emergencies for
insufficient generating capacity.
R3.2.
Develop, maintain, and implement a set of plans to mitigate operating emergencies on
the transmission system.
R3.3.
Develop, maintain, and implement a set of plans for load shedding.
R3.4.
Develop, maintain, and implement a set of plans for system restoration.
Each Transmission Operator and Balancing Authority shall have emergency plans that will
enable it to mitigate operating emergencies. At a minimum, Transmission Operator and
Balancing Authority emergency plans shall include:
R4.1.
Communications protocols to be used during emergencies.
R4.2.
A list of controlling actions to resolve the emergency. Load reduction, in sufficient
quantity to resolve the emergency within NERC-established timelines, shall be one of
the controlling actions.
R4.3.
The tasks to be coordinated with and among adjacent Transmission Operators and
Balancing Authorities.
R4.4.
Staffing levels for the emergency.
Each Transmission Operator and Balancing Authority shall include the applicable elements in
Attachment 1-EOP-001-0 when developing an emergency plan.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 4
Standard EOP-001-X0 — Emergency Operations Planning
R6.
The Transmission Operator and Balancing Authority shall annually review and update each
emergency plan. The Transmission Operator and Balancing Authority shall provide a copy of
its updated emergency plans to its Reliability Coordinator and to neighboring Transmission
Operators and Balancing Authorities.
R7.
The Transmission Operator and Balancing Authority shall coordinate its emergency plans with
other Transmission Operators and Balancing Authorities as appropriate. This coordination
includes the following steps, as applicable:
R7.1.
The Transmission Operator and Balancing Authority shall establish and maintain
reliable communications between interconnected systems.
R7.2.
The Transmission Operator and Balancing Authority shall arrange new interchange
agreements to provide for emergency capacity or energy transfers if existing
agreements cannot be used.
R7.3.
The Transmission Operator and Balancing Authority shall coordinate transmission
and generator maintenance schedules, including outages to the Generator
Interconnection Facility, to maximize capacity or conserve the fuel in short supply.
(This includes water for hydro generators.)
R7.4.
The Transmission Operator and Balancing Authority shall arrange deliveries of
electrical energy or fuel from remote systems through normal operating channels.
C. Measures
M1. The Transmission Operator and Balancing Authority shall have its emergency plans available
for review by the Regional Reliability Organization at all times.
M2. The Transmission Operator and Balancing Authority shall have its two most recent annual selfassessments available for review by the Regional Reliability Organization at all times.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframes
The Regional Reliability Organization shall review and evaluate emergency plans every
three years to ensure that the plans consider the applicable elements of Attachment 1EOP-001-0.
The Regional Reliability Organization may elect to request self-certification of the
Transmission Operator and Balancing Authority in years that the full review is not done.
Reset: one calendar year.
1.3. Data Retention
Current plan available at all times.
1.4. Additional Compliance Information
Not specified.
2.
Levels of Non-Compliance
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 4
Standard EOP-001-X0 — Emergency Operations Planning
2.1. Level 1:
One of the applicable elements of Attachment 1-EOP-001-0X has not
been addressed in the emergency plans.
2.2. Level 2:
Two of the applicable elements of Attachment 1-EOP-001-0X have not
been addressed in the emergency plans.
2.3. Level 3:
Three of the applicable elements of Attachment 1-EOP-001-X0 have not
been addressed in the emergency plans.
2.4. Level 4:
Four or more of the applicable elements of Attachment 1-EOP-001-0X
have not been addressed in the emergency plans or a plan does not exist.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
X
TBD
Modified R7.3 to include the Generator
Interconnection Facility
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
3 of 4
Standard EOP-001-0X – Emergency Operations Planning
Attachment 1-EOP-001-0X
Elements for Consideration in Development of Emergency Plans
1. Fuel supply and inventory — An adequate fuel supply and inventory plan that recognizes reasonable
delays or problems in the delivery or production of fuel.
2. Fuel switching — Fuel switching plans for units for which fuel supply shortages may occur, e.g., gas
and light oil.
3. Environmental constraints — Plans to seek removal of environmental constraints for generating units
and plants.
4. System energy use — The reduction of the system’s own energy use to a minimum.
5. Public appeals — Appeals to the public through all media for voluntary load reductions and energy
conservation including educational messages on how to accomplish such load reduction and
conservation.
6. Load management — Implementation of load management and voltage reductions, if appropriate.
7. Optimize fuel supply — The operation of all generating sources to optimize the availability.
8. Appeals to customers to use alternate fuels — In a fuel emergency, appeals to large industrial and
commercial customers to reduce non-essential energy use and maximize the use of customer-owned
generation that rely on fuels other than the one in short supply.
9. Interruptible and curtailable loads — Use of interruptible and curtailable customer load to reduce
capacity requirements or to conserve the fuel in short supply.
10. Maximizing generator output and availability — The operation of all generating sources to maximize
output and availability. This should include plans to winterize units and plants during extreme cold
weather.
11. Notifying IPPs — Notification of cogeneration and independent power producers to maximize output
and availability.
12. Requests of government — Requests to appropriate government agencies to implement programs to
achieve necessary energy reductions.
13. Load curtailment — A mandatory load curtailment plan to use as a last resort. This plan should
address the needs of critical loads essential to the health, safety, and welfare of the community.
Address firm load curtailment.
14. Notification of government agencies — Notification of appropriate government agencies as the
various steps of the emergency plan are implemented.
15. Notifications to operating entities — Notifications to other operating entities as steps in emergency
plan are implemented.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
4 of 4
Standard EOP-003-X1 — Load Shedding Plans
A. Introduction
1.
Title:
Load Shedding Plans
2.
Number:
EOP-003-X1
3.
Purpose: A Balancing Authority and Transmission Operator operating with
insufficient generation or transmission capacity must have the capability and authority
to shed load rather than risk an uncontrolled failure of the Interconnection.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Generator Operators.
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
After taking all other remedial steps, a Transmission Operator or Balancing Authority
operating with insufficient generation or transmission capacity shall shed customer
load rather than risk an uncontrolled failure of components or cascading outages of the
Interconnection.
R2.
Each Transmission Operator and Balancing Authority shall establish plans for
automatic load shedding for underfrequency or undervoltage conditions.
R3.
Each Transmission Operator and Balancing Authority shall coordinate load shedding
plans among other interconnected Transmission Operators and Balancing Authorities.
R4.
A Transmission Operator or Balancing Authority shall consider one or more of these
factors in designing an automatic load shedding scheme: frequency, rate of frequency
decay, voltage level, rate of voltage decay, or power flow levels.
R5.
A Transmission Operator or Balancing Authority shall implement load shedding in
steps established to minimize the risk of further uncontrolled separation, loss of
generation, or system shutdown.
R6.
After a Transmission Operator or Balancing Authority Area separates from the
Interconnection, if there is insufficient generating capacity to restore system frequency
following automatic underfrequency load shedding, the Transmission Operator or
Balancing Authority shall shed additional load.
R7.
The Transmission Operator, Generator Operator, and Balancing Authority shall
coordinate automatic load shedding throughout their areas with underfrequency
isolation of generating units, tripping of shunt capacitors, and other automatic actions
that will occur under abnormal frequency, voltage, or power flow conditions.
R8.
Each Transmission Operator or Balancing Authority shall have plans for operatorcontrolled manual load shedding to respond to real-time emergencies. The
Transmission Operator or Balancing Authority shall be capable of implementing the
load shedding in a timeframe adequate for responding to the emergency.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 1 of 3
Standard EOP-003-X1 — Load Shedding Plans
C. Measures
M1. Each Transmission Operator and Balancing Authority that has or directs the
deployment of undervoltage and/or underfrequency load shedding facilities, shall have
and provide upon request, its automatic load shedding plans.(Requirement 2)
M2. Each Transmission Operator and Balancing Authority shall have and provide upon
request its manual load shedding plans that will be used to confirm that it meets
Requirement 8. (Part 1)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Additional Reporting Requirement
No additional reporting required.
1.4. Data Retention
Each Balancing Authority and Transmission Operator shall have its current, inforce load shedding plans.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 2 of 3
Standard EOP-003-X1 — Load Shedding Plans
The Compliance Monitor shall keep the last periodic audit report and all requested
and submitted subsequent compliance records.
1.5. Additional Compliance Information
None.
Levels of Non-Compliance:
2.
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not Applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
2.4.1
Does not have an automatic load shedding plan as specified in R2.
2.4.2
Does not have manual load shedding plans as specified in R8.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
X
TBD
Modified R7 to include Generator
Operator.
Added Generator Operator to
Applicability Section.
Addition
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 3 of 3
Standard EOP-004-X1 — Disturbance Reporting
A. Introduction
1.
Title:
Disturbance Reporting
2.
Number:
EOP-004-X1
3.
Purpose: Disturbances or unusual occurrences that jeopardize the operation of the
Bulk Electric System, or result in system equipment damage or customer interruptions,
need to be studied and understood to minimize the likelihood of similar events in the
future.
4.
Applicability
4.1. Reliability Coordinators.
4.2. Balancing Authorities.
4.3. Transmission Operators.
4.4. Generator Operators.
4.5. Load Serving Entities.
4.6. Regional Reliability Organizations.
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
Each Regional Reliability Organization shall establish and maintain a Regional
reporting procedure to facilitate preparation of preliminary and final disturbance
reports.
R2.
A Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator or Load Serving Entity shall promptly analyze Bulk Electric System
disturbances on its system or facilities, including those for the Generator
Interconnection Facility..
R3.
A Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator or Load Serving Entity experiencing a reportable incident shall provide a
preliminary written report to its Regional Reliability Organization and NERC.
R3.1.
The affected Reliability Coordinator, Balancing Authority, Transmission
Operator, Generator Operator or Load Serving Entity shall submit within 24
hours of the disturbance or unusual occurrence either a copy of the report
submitted to DOE, or, if no DOE report is required, a copy of the NERC
Interconnection Reliability Operating Limit and Preliminary Disturbance
Report form. Events that are not identified until some time after they occur
shall be reported within 24 hours of being recognized.
R3.2.
Applicable reporting forms are provided in Attachments 1-EOP-004 and 2EOP-004.
R3.3.
Under certain adverse conditions, e.g., severe weather, it may not be possible
to assess the damage caused by a disturbance and issue a written
Interconnection Reliability Operating Limit and Preliminary Disturbance
Report within 24 hours. In such cases, the affected Reliability Coordinator,
Balancing Authority, Transmission Operator, Generator Operator, or Load
Serving Entity shall promptly notify its Regional Reliability Organization(s)
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 1 of 14
Standard EOP-004-X1 — Disturbance Reporting
and NERC, and verbally provide as much information as is available at that
time. The affected Reliability Coordinator, Balancing Authority, Transmission
Operator, Generator Operator, or Load Serving Entity shall then provide
timely, periodic verbal updates until adequate information is available to issue
a written Preliminary Disturbance Report.
R3.4.
If, in the judgment of the Regional Reliability Organization, after consultation
with the Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, or Load Serving Entity in which a disturbance occurred, a
final report is required, the affected Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, or Load Serving Entity
shall prepare this report within 60 days. As a minimum, the final report shall
have a discussion of the events and its cause, the conclusions reached, and
recommendations to prevent recurrence of this type of event. The report shall
be subject to Regional Reliability Organization approval.
R4.
When a Bulk Electric System disturbance occurs, the Regional Reliability Organization
shall make its representatives on the NERC Operating Committee and Disturbance
Analysis Working Group available to the affected Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, or Load Serving Entity
immediately affected by the disturbance for the purpose of providing any needed
assistance in the investigation and to assist in the preparation of a final report.
R5.
The Regional Reliability Organization shall track and review the status of all final
report recommendations at least twice each year to ensure they are being acted upon in
a timely manner. If any recommendation has not been acted on within two years, or if
Regional Reliability Organization tracking and review indicates at any time that any
recommendation is not being acted on with sufficient diligence, the Regional
Reliability Organization shall notify the NERC Planning Committee and Operating
Committee of the status of the recommendation(s) and the steps the Regional
Reliability Organization has taken to accelerate implementation.
C. Measures
M1. The Regional Reliability Organization shall have and provide upon request as
evidence, its current regional reporting procedure that is used to facilitate preparation
of preliminary and final disturbance reports. (Requirement 1)
M2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, and Load-Serving Entity that has a reportable incident shall have and provide
upon request evidence that could include, but is not limited to, the preliminary report,
computer printouts, operator logs, or other equivalent evidence that will be used to
confirm that it prepared and delivered the NERC Interconnection Reliability Operating
Limit and Preliminary Disturbance Reports to NERC within 24 hours of its recognition
as specified in Requirement 3.1.
M3. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, and/or Load Serving Entity that has a reportable incident shall have and
provide upon request evidence that could include, but is not limited to, operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or other
equivalent evidence that will be used to confirm that it provided information verbally
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 2 of 14
Standard EOP-004-X1 — Disturbance Reporting
as time permitted, when system conditions precluded the preparation of a report in 24
hours. (Requirement 3.3)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability
Organizations.
Regional Reliability Organizations shall be responsible for compliance monitoring
of Reliability Coordinators, Balancing Authorities, Transmission Operators,
Generator Operators, and Load-serving Entities.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
Each Regional Reliability Organization shall have its current, in-force, regional
reporting procedure as evidence of compliance. (Measure 1)
Each Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, and/or Load Serving Entity that is either involved in a Bulk
Electric System disturbance or has a reportable incident shall keep data related to
the incident for a year from the event or for the duration of any regional
investigation, whichever is longer. (Measures 2 through 4)
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 3 of 14
Standard EOP-004-X1 — Disturbance Reporting
The Compliance Monitor shall keep the last periodic audit report and all requested
and submitted subsequent compliance records.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 4 of 14
Standard EOP-004-X1 — Disturbance Reporting
1.4. Additional Compliance Information
See Attachments:
- EOP-004 Disturbance Reporting Form
- Table 1 EOP-004
Levels of Non-Compliance for a Regional Reliability Organization
2.
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: No current procedure to facilitate preparation of preliminary and final
disturbance reports as specified in R1.
Levels of Non-Compliance for a Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, and Load- Serving Entity:
3.
3.1. Level 1: There shall be a level one non-compliance if any of the following
conditions exist:
3.1.1
Failed to prepare and deliver the NERC Interconnection Reliability
Operating Limit and Preliminary Disturbance Reports to NERC within 24
hours of its recognition as specified in Requirement 3.1
3.1.2
Failed to provide disturbance information verbally as time permitted,
when system conditions precluded the preparation of a report in 24 hours
as specified in R3.3
3.1.3
Failed to prepare a final report within 60 days as specified in R3.4
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable
3.4. Level 4: Not applicable.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
May 23, 2005
Fixed reference to attachments 1-EOP004-0 and 2-EOP-004-0, Changed chart
title 1-FAC-004-0 to 1-EOP-004-0,
Fixed title of Table 1 to read 1-EOP004-0, and fixed font.
Errata
0
July 6, 2005
Fixed email in Attachment 1-EOP-004-0 Errata
from info@nerc.com to
esisac@nerc.com.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 5 of 14
Standard EOP-004-X1 — Disturbance Reporting
0
July 26, 2005
Fixed Header on page 8 to read EOP004-0
Errata
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
X
TBD
Modified R2 to include the Generator
Interconnection Facility.
Addition
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 6 of 14
Standard EOP-004-X1 — Disturbance Reporting
Attachment 1-EOP-004
NERC Disturbance Report Form
Introduction
These disturbance reporting requirements apply to all Reliability Coordinators, Balancing
Authorities, Transmission Operators, Generator Operators, and Load Serving Entities, and
provide a common basis for all NERC disturbance reporting. The entity on whose system a
reportable disturbance occurs shall notify NERC and its Regional Reliability Organization of the
disturbance using the NERC Interconnection Reliability Operating Limit and Preliminary
Disturbance Report forms. Reports can be sent to NERC via email (esisac@nerc.com) by
facsimile (609-452-9550) using the NERC Interconnection Reliability Operating Limit and
Preliminary Disturbance Report forms. If a disturbance is to be reported to the U.S. Department
of Energy also, the responding entity may use the DOE reporting form when reporting to NERC.
Note: All Emergency Incident and Disturbance Reports (Schedules 1 and 2) sent to DOE shall be
simultaneously sent to NERC, preferably electronically at esisac@nerc.com.
The NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports are
to be made for any of the following events:
1.
2.
3.
4.
5.
The loss of a bulk power transmission component that significantly affects the integrity of
interconnected system operations. Generally, a disturbance report will be required if the
event results in actions such as:
a.
Modification of operating procedures.
b.
Modification of equipment (e.g. control systems or special protection systems) to
prevent reoccurrence of the event.
c.
Identification of valuable lessons learned.
d.
Identification of non-compliance with NERC standards or policies.
e.
Identification of a disturbance that is beyond recognized criteria, i.e. three-phase fault
with breaker failure, etc.
f.
Frequency or voltage going below the under-frequency or under-voltage load shed
points.
The occurrence of an interconnected system separation or system islanding or both.
Loss of generation by a Generator Operator, Balancing Authority, or Load-Serving Entity
2,000 MW or more in the Eastern Interconnection or Western Interconnection and 1,000
MW or more in the ERCOT Interconnection.
Equipment failures/system operational actions which result in the loss of firm system
demands for more than 15 minutes, as described below:
a.
Entities with a previous year recorded peak demand of more than 3,000 MW are
required to report all such losses of firm demands totaling more than 300 MW.
b.
All other entities are required to report all such losses of firm demands totaling more
than 200 MW or 50% of the total customers being supplied immediately prior to the
incident, whichever is less.
Firm load shedding of 100 MW or more to maintain the continuity of the bulk electric
system.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 7 of 14
Standard EOP-004-X1 — Disturbance Reporting
6.
7.
8.
Any action taken by a Generator Operator, Transmission Operator, Balancing Authority, or
Load-Serving Entity that results in:
a.
Sustained voltage excursions equal to or greater than ±10%, or
b.
Major damage to power system components, or
c.
Failure, degradation, or misoperation of system protection, special protection schemes,
remedial action schemes, or other operating systems that do not require operator
intervention, which did result in, or could have resulted in, a system disturbance as
defined by steps 1 through 5 above.
An Interconnection Reliability Operating Limit (IROL) violation as required in reliability
standard TOP-007.
Any event that the Operating Committee requests to be submitted to Disturbance Analysis
Working Group (DAWG) for review because of the nature of the disturbance and the
insight and lessons the electricity supply and delivery industry could learn.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 8 of 14
Standard EOP-004-X1 — Disturbance Reporting
NERC Interconnection Reliability Operating Limit and Preliminary Disturbance
Report
Check here if this is an Interconnection Reliability Operating Limit (IROL) violation report.
1. Organization filing report.
2. Name of person filing report.
3. Telephone number.
4. Date and time of disturbance.
Date:(mm/dd/yy)
Time/Zone:
5. Did the disturbance originate in your
system?
Yes
No
6. Describe disturbance including: cause,
equipment damage, critical services
interrupted, system separation, key
scheduled and actual flows prior to
disturbance and in the case of a
disturbance involving a special
protection or remedial action scheme,
what action is being taken to prevent
recurrence.
7. Generation tripped.
MW Total
List generation tripped
8. Frequency.
Just prior to disturbance (Hz):
Immediately after disturbance (Hz
max.):
Immediately after disturbance (Hz
min.):
9. List transmission lines tripped (specify
voltage level of each line).
10.
FIRM
INTERRUPTIBLE
Demand tripped (MW):
Number of affected Customers:
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 9 of 14
Standard EOP-004-X1 — Disturbance Reporting
Demand lost (MW-Minutes):
11. Restoration time.
INITIAL
FINAL
Transmission:
Generation:
Demand:
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 10 of 14
Standard EOP-004-X1 — Disturbance Reporting
Attachment 2-EOP-004
U.S. Department of Energy Disturbance Reporting Requirements
Introduction
The U.S. Department of Energy (DOE), under its relevant authorities, has established mandatory
reporting requirements for electric emergency incidents and disturbances in the United States.
DOE collects this information from the electric power industry on Form EIA-417 to meet its
overall national security and Federal Energy Management Agency’s Federal Response Plan
(FRP) responsibilities. DOE will use the data from this form to obtain current information
regarding emergency situations on U.S. electric energy supply systems. DOE’s Energy
Information Administration (EIA) will use the data for reporting on electric power emergency
incidents and disturbances in monthly EIA reports. In addition, the data may be used to develop
legislative recommendations, reports to the Congress and as a basis for DOE investigations
following severe, prolonged, or repeated electric power reliability problems.
Every Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator
or Load Serving Entity must use this form to submit mandatory reports of electric power system
incidents or disturbances to the DOE Operations Center, which operates on a 24-hour basis,
seven days a week. All other entities operating electric systems have filing responsibilities to
provide information to the Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator or Load Serving Entity when necessary for their reporting obligations and to
file form EIA-417 in cases where these entities will not be involved. EIA requests that it be
notified of those that plan to file jointly and of those electric entities that want to file separately.
Special reporting provisions exist for those electric utilities located within the United States, but
for whom Reliability Coordinator oversight responsibilities are handled by electrical systems
located across an international border. A foreign utility handling U.S. Balancing Authority
responsibilities, may wish to file this information voluntarily to the DOE. Any U.S.-based utility
in this international situation needs to inform DOE that these filings will come from a foreignbased electric system or file the required reports themselves.
Form EIA-417 must be submitted to the DOE Operations Center if any one of the following
applies (see Table 1-EOP-004-0 — Summary of NERC and DOE Reporting Requirements for
Major Electric System Emergencies):
1. Uncontrolled loss of 300 MW or more of firm system load for more than 15 minutes from a
2.
3.
4.
5.
single incident.
Load shedding of 100 MW or more implemented under emergency operational policy.
System-wide voltage reductions of 3 percent or more.
Public appeal to reduce the use of electricity for purposes of maintaining the continuity of the
electric power system.
Actual or suspected physical attacks that could impact electric power system adequacy or
reliability; or vandalism, which target components of any security system. Actual or
suspected cyber or communications attacks that could impact electric power system
adequacy or vulnerability.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 11 of 14
Standard EOP-004-X1 — Disturbance Reporting
6. Actual or suspected cyber or communications attacks that could impact electric power system
adequacy or vulnerability.
7. Fuel supply emergencies that could impact electric power system adequacy or reliability.
8. Loss of electric service to more than 50,000 customers for one hour or more.
9. Complete operational failure or shut-down of the transmission and/or distribution electrical
system.
The initial DOE Emergency Incident and Disturbance Report (form EIA-417 – Schedule 1) shall
be submitted to the DOE Operations Center within 60 minutes of the time of the system
disruption. Complete information may not be available at the time of the disruption. However,
provide as much information as is known or suspected at the time of the initial filing. If the
incident is having a critical impact on operations, a telephone notification to the DOE Operations
Center (202-586-8100) is acceptable, pending submission of the completed form EIA-417.
Electronic submission via an on-line web-based form is the preferred method of notification.
However, electronic submission by facsimile or email is acceptable.
An updated form EIA-417 (Schedule 1 and 2) is due within 48 hours of the event to provide
complete disruption information. Electronic submission via facsimile or email is the preferred
method of notification. Detailed DOE Incident and Disturbance reporting requirements can be
found at: ftp://ftp.eia.doe.gov/pub/electricity/eiafor417.doc.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 12 of 14
Standard EOP-004-X1 — Disturbance Reporting
Table 1-EOP-004-0
Summary of NERC and DOE Reporting Requirements for Major Electric System
Emergencies
Incident
Report
Incident
Threshold
Time
No.
Required
EIA – SchUncontrolled loss
1 hour
1
of Firm System
≥ 300 MW – 15 minutes or more
48
1
EIA – SchLoad
hour
2
EIA – Sch1 hour
≥ 100 MW under emergency
1
Load Shedding
48
2
operational policy
EIA – Schhour
2
EIA – Sch1 hour
Voltage
1
3% or more – applied system-wide
48
3
Reductions
EIA – Schhour
2
EIA – Sch1 hour
Emergency conditions to reduce
1
Public Appeals
48
4
demand
EIA – Schhour
2
EIA – SchPhysical sabotage,
1 hour
On physical security systems –
1
terrorism or
48
5
suspected or real
EIA – Schvandalism
hour
2
EIA – SchCyber sabotage,
1 hour
If the attempt is believed to have or
1
terrorism or
48
6
did happen
EIA – Schvandalism
hour
2
EIA – Sch1 hour
Fuel supply
Fuel inventory or hydro storage levels 1
48
7
emergencies
≤ 50% of normal
EIA – Schhour
2
EIA – Sch1 hour
Loss of electric
1
≥ 50,000 for 1 hour or more
48
8
service
EIA – Schhour
2
Complete
EIA – SchIf isolated or interconnected electrical
1 hour
operation failure
1
systems suffer total electrical system
48
9
of electrical
EIA – Schcollapse
hour
system
2
All DOE EIA-417 Schedule 1 reports are to be filed within 60-minutes after the start of an
incident or disturbance
All DOE EIA-417 Schedule 2 reports are to be filed within 48-hours after the start of an
incident or disturbance
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 13 of 14
Standard EOP-004-X1 — Disturbance Reporting
All entities required to file a DOE EIA-417 report (Schedule 1 & 2) shall send a copy of these
reports to NERC simultaneously, but no later than 24 hours after the start of the incident or
disturbance.
Incident
Report
Incident
Threshold
Time
No.
Required
NERC
24
Loss of major
Significantly affects integrity of
Prelim
hour
1
system component
interconnected system operations
Final
60 day
report
Interconnected
NERC
Total system shutdown
24
system separation
Prelim
Partial shutdown, separation, or
hour
2
or system
Final
islanding
60 day
islanding
report
NERC
≥ 2,000 – Eastern Interconnection
24
Prelim
Loss of generation
≥ 2,000 – Western Interconnection
hour
3
Final
≥ 1,000 – ERCOT Interconnection
60 day
report
Entities with peak demand ≥3,000:
NERC
24
Loss of firm load
loss ≥300 MW
Prelim
hour
4
≥15-minutes
All others ≥200MW or 50% of total
Final
60 day
demand
report
NERC
24
Firm load
≥100 MW to maintain continuity of
Prelim
hour
5
shedding
bulk system
Final
60 day
report
Voltage excursions ≥10%
System operation
NERC
24
Major damage to system
or operation
Prelim
hour
6
components
actions resulting
Final
60 day
Failure,
degradation,
or
in:
report
misoperation of SPS
NERC
72
Prelim
IROL violation
Reliability standard TOP-007.
hour
7
Final
60 day
report
NERC
Due to nature of disturbance &
24
As requested by
Prelim
usefulness to industry (lessons
hour
8
ORS Chairman
Final
learned)
60 day
report
All NERC Operating Security Limit and Preliminary Disturbance reports will be filed within 24
hours after the start of the incident. If an entity must file a DOE EIA-417 report on an incident,
which requires a NERC Preliminary report, the Entity may use the DOE EIA-417 form for both
DOE and NERC reports.
Any entity reporting a DOE or NERC incident or disturbance has the responsibility to also
notify its Regional Reliability Organization.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 14 of 14
Standard EOP-008-X0 — Plans for Loss of Control Center Functionality
A. Introduction
1.
Title:
Plans for Loss of Control Center Functionality
2.
Number:
EOP-008-X0
3.
Purpose:
Each reliability entity must have a plan to continue reliability operations in the
event its control center becomes inoperable.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have a
plan to continue reliability operations in the event its control center becomes inoperable. The
contingency plan must meet the following requirements:
R1.1.
The contingency plan shall not rely on data or voice communication from the primary
control facility to be viable.
R1.2.
The plan shall include procedures and responsibilities for providing basic tie line
control and procedures and for maintaining the status of all inter-area schedules, such
that there is an hourly accounting of all schedules.
R1.3.
The contingency plan must address monitoring and control of critical transmission
facilities, Generator Interconnection Operational Interface, generation control, voltage
control, time and frequency control, control of critical substation devices, and logging
of significant power system events. The plan shall list the critical facilities.
R1.4.
The plan shall include procedures and responsibilities for maintaining basic voice
communication capabilities with other areas.
R1.5.
The plan shall include procedures and responsibilities for conducting periodic tests, at
least annually, to ensure viability of the plan.
R1.6.
The plan shall include procedures and responsibilities for providing annual training to
ensure that operating personnel are able to implement the contingency plans.
R1.7.
The plan shall be reviewed and updated annually.
R1.8.
Interim provisions must be included if it is expected to take more than one hour to
implement the contingency plan for loss of primary control facility.
C. Measures
M1. Evidence that the Reliability Coordinator, Transmission Operator or Balancing Authority has
developed and documented a current contingency plan to continue the monitoring and
operation of the electrical equipment under its control to maintain Bulk Electrical System
reliability if its primary control facility becomes inoperable.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 2
Standard EOP-008-X0 — Plans for Loss of Control Center Functionality
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
Periodic Review: Review and evaluate the plan for loss of primary control facility
contingency as part of the three-year on-site audit process. The audit must include a
demonstration of the plan by the Reliability Coordinator, Transmission Operator, and
Balancing Authority.
Reset: One calendar year.
1.3. Data Retention
The contingency plan for loss of primary control facility must be available for review at
all times.
1.4. Additional Compliance Information
Not specified.
2.
Levels of Non-Compliance
2.1. Level 1:
NA
2.2. Level 2:
A contingency plan has been implemented and tested, but has not been
tested in the past year or there are no records of shift operating personnel training.
2.3. Level 3:
A contingency plan has been implemented, but does not include all of the
elements contained in Requirements R1.1–R1.8.
2.4. Level 4:
A contingency plan has not been developed, implemented, and tested.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
X
TBD
Modified R1.3 to include Generator
Interconnection Operational Interface
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 2
Standard FAC-001-0 X — Facility Connection Requirements
A.
Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 X
3.
Purpose: To avoid adverse impacts on reliability, Transmission Owners must establish
facility connection and performance requirements.
4.
Applicability:
4.1.
5.
B.
Transmission Owner
Effective Date:
April 1, 2005TBD
Requirements
R1. The Transmission Owner shall document, maintain, and publish facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability Organization, subregional, Power Pool, and individual Transmission Owner
planning criteria and facility connection requirements. The Transmission Owner’s facility
connection requirements shall address connection requirements for:
R1.1. Generation facilities, including the Generator Interconnection Facility,
R1.2. Transmission facilities, and
R1.3. End-user facilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
R2.1. Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Procedures for coordinated joint studies of new facilities and their impacts on
the interconnected transmission systems.
R2.1.2. Procedures for notification of new or modified facilities to others (those
responsible for the reliability of the interconnected transmission systems) as
soon as feasible.
R2.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
R2.1.4. Breaker duty and surge protection.
R2.1.5. System protection and coordination.
R2.1.6. Metering and telecommunications.
R2.1.7. Grounding and safety issues.
R2.1.8. Insulation and insulation coordination.
R2.1.9. Voltage, Reactive Power, and power factor control.
R2.1.10. Power quality impacts.
R2.1.11. Equipment Ratings.
R2.1.12. Synchronizing of facilities.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 3
Standard FAC-001-0 X — Facility Connection Requirements
R2.1.13. Maintenance coordination.
R2.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15. Inspection requirements for existing or new facilities.
R2.1.16. Communications and procedures during normal and emergency operating
conditions.
R3. The Transmission Owner shall maintain and update its facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Reliability Organization, and NERC on
request (five business days).
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R1.
M2. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all requirements stated in Reliability Standard FAC-001-0_R2.
M3. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R3.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
1.2.
Compliance Monitoring Period and Reset Timeframe
On request (five business days).
1.3.
Data Retention
None specified.
1.4.
Additional Compliance Information
None.
Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 3
Standard FAC-001-0 X — Facility Connection Requirements
2.4.
E.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
X
TBD
Modified R1.1 to include the Generator
Interconnection Facility
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
3 of 3
Standard FAC-003-X1 — Transmission Vegetation Management Program
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X1
3.
Purpose: To improve the reliability of the electric transmission systems by preventing
outages from vegetation located on transmission rights-of-way (ROW) and minimizing
outages from vegetation located adjacent to ROW, maintaining clearances between
transmission lines and vegetation on and along transmission ROW, and reporting vegetationrelated outages of the transmission systems to the respective Regional Reliability
Organizations (RRO) and the North American Electric Reliability Council (NERC).
4.
Applicability:
4.1. Transmission Owner.
4.2. Regional Reliability Organization.
4.3. This standard shall apply to all transmission lines operated at 200 kV and above and to
any lower voltage lines designated by the RRO as critical to the reliability of the
electric system in the region.
4.4. Generator Owner.
4.5. This standard shall apply to the Generator Interconnection Facility above 200 kV that
exceed two spans from the generator property line or are otherwise deemed critical by
the Regional Entity below 200 kV (subject to the two-span criteria.)
5.
Effective Dates:
5.1.One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.5.1.
Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.TBD
B.
Requirements
R1. The Transmission Owner and Generator Owner shall prepare, and keep current, a formal
transmission vegetation management program (TVMP). The TVMP shall include the
Transmission Owner’s and Generator Owner’s objectives, practices, approved procedures, and
work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the Transmission Owner’s or Generator Owner’s
transmission lines.
R1.2. The Transmission Owner and Generator Owner, in the TVMP, shall identify and
document clearances between vegetation and any overhead, ungrounded supply
conductors, taking into consideration transmission line voltage, the effects of ambient
temperature on conductor sag under maximum design loading, and the effects of wind
velocities on conductor sway. Specifically, the Transmission Owner and Generator
Owner shall establish clearances to be achieved at the time of vegetation management
work identified herein as Clearance 1, and shall also establish and maintain a set of
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
1 of 6
Standard FAC-003-X1 — Transmission Vegetation Management Program
clearances identified herein as Clearance 2 to prevent flashover between vegetation and
overhead ungrounded supply conductors.
R1.2.1. Clearance 1 — The Transmission Owner and Generator Owner shall
determine and document appropriate clearance distances to be achieved at the
time of transmission vegetation management work based upon local
conditions and the expected time frame in which the Transmission Owner or
Generator Owner plans to return for future vegetation management work.
Local conditions may include, but are not limited to: operating voltage,
appropriate vegetation management techniques, fire risk, reasonably
anticipated tree and conductor movement, species types and growth rates,
species failure characteristics, local climate and rainfall patterns, line terrain
and elevation, location of the vegetation within the span, and worker approach
distance requirements. Clearance 1 distances shall be greater than those
defined by Clearance 2 below.
R1.2.2. Clearance 2 — The Transmission Owner and Generator Owner shall
determine and document specific radial clearances to be maintained between
vegetation and conductors under all rated electrical operating conditions.
These minimum clearance distances are necessary to prevent flashover
between vegetation and conductors and will vary due to such factors as
altitude and operating voltage. These Transmission Owner-specific and
Generator Owner-specific minimum clearance distances shall be no less than
those set forth in the Institute of Electrical and Electronics Engineers (IEEE)
Standard 516-2003 (Guide for Maintenance Methods on Energized Power
Lines) and as specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each Transmission Owner and Generator Owner shall develop mitigation measures to
achieve sufficient clearances for the protection of the transmission facilities when it
identifies locations on the ROW where the Transmission Owner or Generator Owner is
restricted from attaining the clearances specified in Requirement 1.2.1.
R1.5. Each Transmission Owner and Generator Owner shall establish and document a
process for the immediate communication of vegetation conditions that present an
imminent threat of a transmission line outage. This is so that action (temporary
reduction in line rating, switching line out of service, etc.) may be taken until the threat
is relieved.
R2. The Transmission Owner and Generator Owner shall create and implement an annual plan for
vegetation management work to ensure the reliability of the system. The plan shall describe
the methods used, such as manual clearing, mechanical clearing, herbicide treatment, or other
actions. The plan should be flexible enough to adjust to changing conditions, taking into
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
2 of 6
Standard FAC-003-X1 — Transmission Vegetation Management Program
consideration anticipated growth of vegetation and all other environmental factors that may
have an impact on the reliability of the transmission systems. Adjustments to the plan shall be
documented as they occur. The plan should take into consideration the time required to obtain
permissions or permits from landowners or regulatory authorities. Each Transmission Owner
and Generator Owner shall have systems and procedures for documenting and tracking the
planned vegetation management work and ensuring that the vegetation management work was
completed according to work specifications.
R3. The Transmission Owner and Generator Owner shall report quarterly to its RRO, or the
RRO’s designee, sustained transmission line outages determined by the Transmission Owner
or Generator Owner to have been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The Transmission Owner or Generator Owner is not required to report to the RRO, or
the RRO’s designee, certain sustained transmission line outages caused by vegetation:
(1) Vegetation-related outages that result from vegetation falling into lines from
outside the ROW that result from natural disasters shall not be considered reportable
(examples of disasters that could create non-reportable outages include, but are not
limited to, earthquakes, fires, tornados, hurricanes, landslides, wind shear, major
storms as defined either by the Transmission Owner, Generator Owner, or an
applicable regulatory body, ice storms, and floods), and (2) Vegetation-related outages
due to human or animal activity shall not be considered reportable (examples of
human or animal activity that could cause a non-reportable outage include, but are not
limited to, logging, animal severing tree, vehicle contact with tree, arboricultural
activities or horticultural or agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the Transmission Owner or Generator Owner to
the RRO, or the RRO’s designee, shall include at a minimum: the name of the
circuit(s) outaged, the date, time and duration of the outage; a description of the cause
of the outage; other pertinent comments; and any countermeasures taken by the
Transmission Owner or Generator Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
R4. The RRO shall report the outage information provided to it by Transmission Owner’s, as
required by Requirement 3, quarterly to NERC, as well as any actions taken by the RRO as a
result of any of the reported outages.
C.
Measures
M1. The Transmission Owner has a documented TVMP, as identified in Requirement 1.
M1.1. The Transmission Owner has documentation that the Transmission Owner performed
the vegetation inspections as identified in Requirement 1.1.
M1.2. The Transmission Owner has documentation that describes the clearances identified in
Requirement 1.2.
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
3 of 6
Standard FAC-003-X1 — Transmission Vegetation Management Program
M1.3. The Transmission Owner has documentation that the personnel directly involved in the
design and implementation of the Transmission Owner’s TVMP hold the qualifications
identified by the Transmission Owner as required in Requirement 1.3.
M1.4. The Transmission Owner has documentation that it has identified any areas not
meeting the Transmission Owner’s standard for vegetation management and any
mitigating measures the Transmission Owner has taken to address these deficiencies as
identified in Requirement 1.4.
M1.5. The Transmission Owner has a documented process for the immediate communication
of imminent threats by vegetation as identified in Requirement 1.5.
M2. The Transmission Owner has documentation that the Transmission Owner implemented the
work plan identified in Requirement 2.
M3. The Transmission Owner has documentation that it has supplied quarterly outage reports to
the RRO, or the RRO’s designee, as identified in Requirement 3.
M4. The RRO has documentation that it provided quarterly outage reports to NERC as identified in
Requirement 4.
D.
Compliance
1.
2.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
RRO
NERC
1.2.
Compliance Monitoring Period and Reset
One calendar Year
1.3.
Data Retention
Five Years
1.4.
Additional Compliance Information
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
Levels of Non-Compliance
2.1.
Level 1:
2.1.1.
The TVMP was incomplete in one of the requirements specified in any
subpart of Requirement 1, or;
2.1.2.
Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.
The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2. Level 2:
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
4 of 6
Standard FAC-003-X1 — Transmission Vegetation Management Program
2.2.1.
The TVMP was incomplete in two of the requirements specified in any
subpart of Requirement 1, or;
2.2.2.
The Transmission Owner was unable to certify during its annual selfcertification that it fully implemented its annual work plan, or documented
deviations from, as specified in Requirement 2.
2.2.3.
The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
2.3. Level 3:
2.4.
E.
2.3.1.
The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.
The Transmission Owner did not maintain a set of clearances (Clearance 2),
as defined in Requirement 1.2.2, to prevent flashover between vegetation
and overhead ungrounded supply conductors, or;
2.3.3.
The TVMP was incomplete in three of the requirements specified in any
subpart of Requirement 1.
Level 4:
2.4.1.
The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
2.4.2.
The TVMP was incomplete in four or more of the requirements specified in
any subpart of Requirement 1.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
TBD
Modified the Applicability Section to
include the Generator Owner and Generator
Interconnection Facility above 200 kV that
exceed two spans from the generator
property line or are otherwise deemed
critical by the Regional Entity below 200
kV (subject to the two-span criteria.).
Addition
Included Generator Owner into the
following Requirements: R1, R1.1, R1.2,
R1.2.1, R1.2.2, R1.3, R1.4, R1.5, R2, R3,
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
5 of 6
Standard FAC-003-X1 — Transmission Vegetation Management Program
R3.2, and R3.3
Adopted by NERC Board of Trustees: February 7, 2006TBD
Effective Date: April 7, 2006TBD
6 of 6
Standard FAC-008-1X — Facility Ratings Methodology
A. Introduction
1.
Title:
Facility Ratings Methodology
2.
Number:
FAC-008-X1
3.
Purpose:
To ensure that Facility Ratings used in the reliable planning and operation of the
Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Transmission Owner
4.2. Generator Owner
5.
Effective Date:
August 7, 2006TBD
B. Requirements
R1.
The Transmission Owner and Generator Owner shall each document its current methodology
used for developing Facility Ratings (Facility Ratings Methodology) of its solely and jointly
owned Facilities, including the Generator Interconnection Facility. The methodology shall
include all of the following:
R1.1.
A statement that a Facility Rating shall equal the most limiting applicable Equipment
Rating of the individual equipment that comprises that Facility.
R1.2.
The method by which the Rating (of major BES equipment that comprises a Facility)
is determined.
R1.2.1. The scope of equipment addressed shall include, but not be limited to,
generators, the Generator Interconnection Facility, transmission conductors,
transformers, relay protective devices, terminal equipment, and series and
shunt compensation devices.
R1.2.2. The scope of Ratings addressed shall include, as a minimum, both Normal
and Emergency Ratings.
R1.3.
Consideration of the following:
R1.3.1. Ratings provided by equipment manufacturers.
R1.3.2. Design criteria (e.g., including applicable references to industry Rating
practices such as manufacturer’s warranty, IEEE, ANSI or other standards).
R1.3.3. Ambient conditions.
R1.3.4. Operating limitations.
R1.3.5. Other assumptions.
R2.
The Transmission Owner and Generator Owner shall each make its Facility Ratings
Methodology available for inspection and technical review by those Reliability Coordinators,
Transmission Operators, Transmission Planners, and Planning Authorities that have
responsibility for the area in which the associated Facilities are located, within 15 business
days of receipt of a request.
R3.
If a Reliability Coordinator, Transmission Operator, Transmission Planner, or Planning
Authority provides written comments on its technical review of a Transmission Owner’s or
Generator Owner’s Facility Ratings Methodology, the Transmission Owner or Generator
Owner shall provide a written response to that commenting entity within 45 calendar days of
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: August 7, 2006TBD
1 of 4
Standard FAC-008-1X — Facility Ratings Methodology
receipt of those comments. The response shall indicate whether a change will be made to the
Facility Ratings Methodology and, if no change will be made to that Facility Ratings
Methodology, the reason why.
C. Measures
M1. The Transmission Owner and Generator Owner shall each have a documented Facility Ratings
Methodology that includes all of the items identified in FAC-008 Requirement 1.1 through
FAC-008 Requirement 1.3.5.
M2. The Transmission Owner and Generator Owner shall each have evidence it made its Facility
Ratings Methodology available for inspection within 15 business days of a request as follows:
M2.1
The Reliability Coordinator shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its Reliability Coordinator Area.
M2.2
The Transmission Operator shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its portion of the Reliability Coordinator Area.
M2.3
The Transmission Planner shall have access to the Facility Ratings Methodologies
used for Rating Facilities in its Transmission Planning Area.
M2.4
The Planning Authority shall have access to the Facility Ratings Methodologies used
for Rating Facilities in its Planning Authority Area.
M3. If the Reliability Coordinator, Transmission Operator, Transmission Planner, or Planning
Authority provides documented comments on its technical review of a Transmission Owner’s
or Generator Owner’s Facility Ratings Methodology, the Transmission Owner or Generator
Owner shall have evidence that it provided a written response to that commenting entity within
45 calendar days of receipt of those comments. The response shall indicate whether a change
will be made to the Facility Ratings Methodology and, if no change will be made to that
Facility Ratings Methodology, the reason why.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Transmission Owner and Generator Owner shall self-certify its compliance to the
Compliance Monitor at least once every three years. New Transmission Owners and
Generator Owners shall each demonstrate compliance through an on-site audit conducted
by the Compliance Monitor within the first year that it commences operation. The
Compliance Monitor shall also conduct an on-site audit once every nine years and an
investigation upon complaint to assess performance.
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
The Transmission Owner and Generator Owner shall each keep all superseded portions of
its Facility Ratings Methodology for 12 months beyond the date of the change in that
methodology and shall keep all documented comments on the Facility Ratings
Methodology and associated responses for three years. In addition, entities found noncompliant shall keep information related to the non-compliance until found compliant.
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: August 7, 2006TBD
2 of 4
Standard FAC-008-1X — Facility Ratings Methodology
The Compliance Monitor shall keep the last audit and all subsequent compliance records.
1.4. Additional Compliance Information
The Transmission Owner and Generator Owner shall each make the following available
for inspection during an on-site audit by the Compliance Monitor or within 15 business
days of a request as part of an investigation upon complaint:
2.
1.4.1
Facility Ratings Methodology
1.4.2
Superseded portions of its Facility Ratings Methodology that had been replaced,
changed or revised within the past 12 months
1.4.3
Documented comments provided by a Reliability Coordinator, Transmission
Operator, Transmission Planner or Planning Authority on its technical review of
a Transmission Owner’s or Generator Owner’s Facility Ratings methodology,
and the associated responses
Levels of Non-Compliance
2.1. Level 1:
exists:
There shall be a level one non-compliance if any of the following conditions
2.1.1
The Facility Ratings Methodology does not contain a statement that a Facility
Rating shall equal the most limiting applicable Equipment Rating of the
individual equipment that comprises that Facility.
2.1.2
The Facility Ratings Methodology does not address one of the required
equipment types identified in FAC-008 R1.2.1.
2.1.3
No evidence of responses to a Reliability Coordinator’s, Transmission Operator,
Transmission Planner, or Planning Authority’s comments on the Facility Ratings
Methodology.
2.2. Level 2:
The Facility Ratings Methodology is missing the assumptions used to
determine Facility Ratings or does not address two of the required equipment types
identified in FAC-008 R1.2.1.
2.3. Level 3:
The Facility Ratings Methodology does not address three of the required
equipment types identified in FAC-008-1 R1.2.1.
2.4. Level 4:
The Facility Ratings Methodology does not address both Normal and
Emergency Ratings or the Facility Ratings Methodology was not made available for
inspection within 15 business days of receipt of a request.
E. Regional Differences
None Identified.
Version History
Version
1
Date
Action
Change Tracking
01/01/05
1.
01/20/05
2.
3.
Lower cased the word “draft” and
“drafting team” where appropriate.
Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
Changed “Timeframe” to “Time
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: August 7, 2006TBD
3 of 4
Standard FAC-008-1X — Facility Ratings Methodology
Frame” and “twelve” to “12” in item
D, 1.2.
X
TBD
Modified R1 and R1.2.1 to include the
Generator Interconnection Facility
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: August 7, 2006TBD
Addition
4 of 4
Standard FAC-009-X1 — Establish and Communicate Facility Ratings
A. Introduction
1.
Title:
Establish and Communicate Facility Ratings
2.
Number:
FAC-009-X1
3.
Purpose:
To ensure that Facility Ratings used in the reliable planning and operation of the
Bulk Electric System (BES) are determined based on an established methodology or
methodologies.
4.
Applicability
4.1. Transmission Owner
4.2. Generator Owner
5.
Effective Date: October 7, 2006TBD
B. Requirements
R1.
The Transmission Owner and Generator Owner shall each establish Facility Ratings for its
solely and jointly owned Facilities, including the Generator Interconnection Facility, that are
consistent with the associated Facility Ratings Methodology.
R2.
The Transmission Owner and Generator Owner shall each provide Facility Ratings for its
solely and jointly owned Facilities, including the Generator Interconnection Facility, that are
existing Facilities, new Facilities, modifications to existing Facilities and re-ratings of existing
Facilities to its associated Reliability Coordinator(s), Planning Authority(ies), Transmission
Planner(s), and Transmission Operator(s) as scheduled by such requesting entities.
C. Measures
M1. The Transmission Owner and Generator Owner shall each be able to demonstrate that it
developed its Facility Ratings consistent with its Facility Ratings Methodology.
M1.1
The Transmission Owner’s and Generator Owner’s Facility Ratings shall each include
ratings for its solely and jointly owned Facilities including new Facilities, existing
Facilities, modifications to existing Facilities and re-ratings of existing Facilities.
M2. The Transmission Owner and Generator Owner shall each have evidence that it provided its
Facility Ratings to its associated Reliability Coordinator(s), Planning Authority(ies),
Transmission Planner(s), and Transmission Operator(s) as scheduled by such requesting
entities.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization
1.2. Compliance Monitoring Period and Reset Time Frame
Each Transmission Owner and Generator Owner shall self-certify its compliance to the
Compliance Monitor annually. The Compliance Monitor may conduct a targeted audit
once in each calendar year (January–December) and an investigation upon complaint to
assess performance.
The Performance-Reset Period shall be twelve months from the last finding of noncompliance.
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: October 7, 2006TBD
1 of 2
Standard FAC-009-X1 — Establish and Communicate Facility Ratings
1.3. Data Retention
The Transmission Owner and Generator Owner shall each keep documentation for 12
months. In addition, entities found non-compliant shall keep information related to the
non-compliance until found compliant.
The Compliance Monitor shall retain audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and Generator Owner shall each make the following available
for inspection during a targeted audit by the Compliance Monitor or within 15 business
days of a request as part of an investigation upon complaint:
2.
1.4.1
Facility Ratings Methodology
1.4.2
Facility Ratings
1.4.3
Evidence that Facility Ratings were distributed
1.4.4
Distribution schedules provided by entities that requested Facility Ratings
Levels of Non-Compliance
2.1. Level 1:
Not all requested Facility Ratings associated with existing Facilities were
provided to the Reliability Coordinator(s), Planning Authority(ies), Transmission
Planner(s), and Transmission Operator(s) in accordance with their respective schedules.
2.2. Level 2:
Not all Facility Ratings associated with new Facilities, modifications to
existing Facilities, and re-ratings of existing Facilities were provided to the Reliability
Coordinator(s), Planning Authority(ies), Transmission Planner(s), and Transmission
Operator(s) in accordance with their respective schedules.
2.3. Level 3:
Facility Ratings provided were not developed consistent with the Facility
Ratings Methodology.
2.4. Level 4:
No Facility Ratings were provided to the Reliability Coordinator(s),
Planning Authority(ies), Transmission Planner(s), or Transmission Operator(s) in
accordance with their respective schedules.
E. Regional Differences
None Identified.
Version History
Version
1
Date
Action
Change Tracking
08/01/05
1.
01/20/06
2.
3.
X
TBD
Lower cased the word “draft” and
“drafting team” where appropriate.
Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
Changed “Timeframe” to “Time
Frame” in item D, 1.2.
Modified R1 and R2 to include the
Generator Interconnection Facility
Adopted by Board of Trustees: February 7, 2006TBD
Effective Date: October 7, 2006TBD
Addition
2 of 2
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
A. Introduction
1.
Title:
Reliability Coordination — Current Day Operations
2.
Number:
IRO-005-X2
3.
Purpose:
The Reliability Coordinator must be continuously aware of conditions within its
Reliability Coordinator Area and include this information in its reliability assessments. The
Reliability Coordinator must monitor Bulk Electric System parameters that may have
significant impacts upon the Reliability Coordinator Area and neighboring Reliability
Coordinator Areas.
4.
Applicability
4.1. Reliability Coordinators.
4.2. Balancing Authorities.
4.3. Transmission Operators.
4.4. Transmission Service Providers.
4.5.
Generator Operators.
4.6. Load-Serving Entities.
4.7. Purchasing-Selling Entities.
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
Each Reliability Coordinator shall monitor its Reliability Coordinator Area parameters,
including but not limited to the following:
R1.1.
Current status of Bulk Electric System elements (transmission or generation including
critical auxiliaries such as Automatic Voltage Regulators and Special Protection
Systems) and system loading.
R1.2.
Current pre-contingency element conditions (voltage, thermal, or stability), including
any applicable mitigation plans to alleviate SOL or IROL violations, including the
plan’s viability and scope.
R1.3.
Current post-contingency element conditions (voltage, thermal, or stability), including
any applicable mitigation plans to alleviate SOL or IROL violations, including the
plan’s viability and scope.
R1.4.
System real and reactive reserves (actual versus required).
R1.5.
Capacity and energy adequacy conditions.
R1.6.
Current ACE for all its Balancing Authorities.
R1.7.
Current local or Transmission Loading Relief procedures in effect.
R1.8.
Planned generation dispatches.
R1.9.
Planned transmission or generation outages.
R1.10. Contingency events.
R2.
Each Reliability Coordinator shall be aware of all Interchange Transactions that wheel through,
source, or sink in its Reliability Coordinator Area, and make that Interchange Transaction
information available to all Reliability Coordinators in the Interconnection.
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 1 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
R3.
As portions of the transmission system approach or exceed SOLs or IROLs, the Reliability
Coordinator shall work with its Transmission Operators and Balancing Authorities to evaluate
and assess any additional Interchange Schedules that would violate those limits. If a potential
or actual IROL violation cannot be avoided through proactive intervention, the Reliability
Coordinator shall initiate control actions or emergency procedures to relieve the violation
without delay, and no longer than 30 minutes. The Reliability Coordinator shall ensure all
resources, including load shedding, are available to address a potential or actual IROL
violation.
R4.
Each Reliability Coordinator shall monitor its Balancing Authorities’ parameters to ensure that
the required amount of operating reserves is provided and available as required to meet the
Control Performance Standard and Disturbance Control Standard requirements. If necessary,
the Reliability Coordinator shall direct the Balancing Authorities in the Reliability Coordinator
Area to arrange for assistance from neighboring Balancing Authorities. The Reliability
Coordinator shall issue Energy Emergency Alerts as needed and at the request of its Balancing
Authorities and Load-Serving Entities.
R5.
Each Reliability Coordinator shall identify the cause of any potential or actual SOL or IROL
violations. The Reliability Coordinator shall initiate the control action or emergency procedure
to relieve the potential or actual IROL violation without delay, and no longer than 30 minutes.
The Reliability Coordinator shall be able to utilize all resources, including load shedding, to
address an IROL violation.
R6.
Each Reliability Coordinator shall ensure its Transmission Operators and Balancing
Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and assist as
needed in the development of any required response plans.
R7.
The Reliability Coordinator shall disseminate information within its Reliability Coordinator
Area, as required.
R8.
Each Reliability Coordinator shall monitor system frequency and its Balancing Authorities’
performance and direct any necessary rebalancing to return to CPS and DCS compliance. The
Transmission Operators and Balancing Authorities shall utilize all resources, including firm
load shedding, as directed by its Reliability Coordinator to relieve the emergent condition.
R9.
The Reliability Coordinator shall coordinate with Transmission Operators, Balancing
Authorities, and Generator Operators as needed to develop and implement action plans to
mitigate potential or actual SOL, IROL, CPS, or DCS violations. The Reliability Coordinator
shall coordinate pending generation and transmission maintenance outages, including the
Generator Interconnection Facility, with Transmission Operators, Balancing Authorities, and
Generator Operators as needed in both the real time and next-day reliability analysis
timeframes.
R10. As necessary, the Reliability Coordinator shall assist the Balancing Authorities in its
Reliability Coordinator Area in arranging for assistance from neighboring Reliability
Coordinator Areas or Balancing Authorities.
R11. The Reliability Coordinator shall identify sources of large Area Control Errors that may be
contributing to Frequency Error, Time Error, or Inadvertent Interchange and shall discuss
corrective actions with the appropriate Balancing Authority. The Reliability Coordinator shall
direct its Balancing Authority to comply with CPS and DCS.
R12. Whenever a Special Protection System that may have an inter-Balancing Authority, or interTransmission Operator impact (e.g., could potentially affect transmission flows resulting in a
SOL or IROL violation) is armed, the Reliability Coordinators shall be aware of the impact of
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 2 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
the operation of that Special Protection System on inter-area flows. The Transmission
Operator shall immediately inform the Reliability Coordinator of the status of the Special
Protection System including any degradation or potential failure to operate as expected.
R13. The Generator Operator shall immediately inform the Transmission Operator of the status of
the Special Protection System, including any degradation or potential failure to operate as
expected for SPS relay or control equipment under its control.
R13.R14.
Each Reliability Coordinator shall ensure that all Transmission Operators,
Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving
Entities, and Purchasing-Selling Entities operate to prevent the likelihood that a disturbance,
action, or non-action in its Reliability Coordinator Area will result in a SOL or IROL violation
in another area of the Interconnection. In instances where there is a difference in derived
limits, the Reliability Coordinator and its Transmission Operators, Balancing Authorities,
Generator Operators, Transmission Service Providers, Load-Serving Entities, and PurchasingSelling Entities shall always operate the Bulk Electric System to the most limiting parameter.
R14.R15.
Each Reliability Coordinator shall make known to Transmission Service
Providers within its Reliability Coordinator Area, SOLs or IROLs within its wide-area view.
The Transmission Service Providers shall respect these SOLs or IROLs in accordance with
filed tariffs and regional Total Transfer Calculation and Available Transfer Calculation
processes.
R15.R16.
Each Reliability Coordinator who foresees a transmission problem (such as
an SOL or IROL violation, loss of reactive reserves, etc.) within its Reliability Coordinator
Area shall issue an alert to all impacted Transmission Operators and Balancing Authorities in
its Reliability Coordinator Area without delay. The receiving Reliability Coordinator shall
disseminate this information to its impacted Transmission Operators and Balancing
Authorities. The Reliability Coordinator shall notify all impacted Transmission Operators,
Balancing Authorities, when the transmission problem has been mitigated.
R16.R17.
Each Reliability Coordinator shall confirm reliability assessment results and
determine the effects within its own and adjacent Reliability Coordinator Areas. The
Reliability Coordinator shall discuss options to mitigate potential or actual SOL or IROL
violations and take actions as necessary to always act in the best interests of the
Interconnection at all times.
When an IROL or SOL is exceeded, the Reliability Coordinator shall
R17.R18.
evaluate the local and wide-area impacts, both real-time and post-contingency, and determine if
the actions being taken are appropriate and sufficient to return the system to within IROL in
thirty minutes. If the actions being taken are not appropriate or sufficient, the Reliability
Coordinator shall direct the Transmission Operator, Balancing Authority, Generator Operator,
or Load-Serving Entity to return the system to within IROL or SOL.
C. Measures
M1. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, Energy Management System description documents, computer printouts, a
prepared report specifically detailing compliance to each of the bullets in Requirement 1, EMS
availability, SCADA data collection system communications performance or equivalent
evidence that will be used to confirm that it monitors the Reliability Coordinator Area
parameters specified in Requirements 1.1 through 1.9.
M2. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, Historical Tag Archive information, Interchange Transaction records,
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 3 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
computer printouts, voice recordings or transcripts of voice recordings or equivalent evidence
that will be used to confirm that it was aware of and made Interchange Transaction information
available to all other Reliability Coordinators, as specified in Requirement 2.
M3. If a potential or actual IROL violation occurs, the Reliability Coordinator involved in the event
shall have and provide upon request evidence that could include, but is not limited to, operator
logs, voice recordings or transcripts of voice recordings, electronic communications, system
event logs, operator action notes or equivalent evidence that will be used to determine if it
initiated control actions or emergency procedures to relieve that IROL violation within 30
minutes. (Requirement 3 Part 2 and Requirement 5)
M4. If one of its Balancing Authorities has insufficient operating reserves, the Reliability
Coordinator shall have and provide upon request evidence that could include, but is not limited
to computer printouts, operating logs, voice recordings or transcripts of voice recordings, or
equivalent evidence that will be used to determine if the Reliability Coordinator directed and, if
needed, assisted the Balancing Authorities in the Reliability Coordinator Area to arrange for
assistance from neighboring Balancing Authorities. (Requirement 4 Part 2 and Requirement
10)
M5. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings,
electronic communications or equivalent evidence that will be used to determine if it informed
Transmission Operators and Balancing Authorities of Geo-Magnetic Disturbance (GMD)
forecast information and provided assistance as needed in the development of any required
response plans. (Requirement 6)
M6. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings, Hot Line
recordings, electronic communications or equivalent evidence that will be used to determine if
it disseminated information within its Reliability Coordinator Area in accordance with
Requirement 7.
M7. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, computer printouts, operator logs, voice recordings or transcripts of voice
recordings, electronic communications or equivalent evidence that will be used to confirm that
it monitored system frequency and Balancing Authority performance and directed any
necessary rebalancing, as specified in Requirement 8 Part 1.
M8. The Transmission Operators and Balancing Authorities shall have and provide upon request
evidence that could include, but is not limited to, operator logs, voice recordings or transcripts
of voice recordings, electronic communications or equivalent evidence that will be used to
confirm that it utilized all resources, including firm load shedding, as directed by its Reliability
Coordinator, to relieve an emergent condition. (Requirement 8 Part 2)
M9. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, voice recordings or transcripts of voice recordings, electronic
communications, operator logs or equivalent evidence that will be used to determine if it
coordinated with Transmission Operators, Balancing Authorities, and Generator Operators as
needed to develop and implement action plans to mitigate potential or actual SOL, IROL, CPS,
or DCS violations including the coordination of pending generation and transmission
maintenance outages with Transmission Operators, Balancing Authorities and Generator
Operators. (Requirement 9 Part 1)
M10. If a large Area Control Error has occurred, the Reliability Coordinator shall have and provide
upon request evidence that could include, but is not limited to, operator logs, voice recordings
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 4 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
or transcripts of voice recordings, Hot Line recordings, electronic communications or
equivalent evidence that will be used to determine if it identified sources of the Area Control
Errors, and initiated corrective actions with the appropriate Balancing Authority if the problem
was within the Reliability Coordinator’s Area (Requirement 11 Part 1)
M11. If a Special Protection System is armed and that system could have had an inter-area impact,
the Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, agreements with their Transmission Operators, procedural documents,
operator logs, computer analysis, training modules, training records or equivalent evidence that
will be used to confirm that it was aware of the impact of that Special Protection System on
inter-area flows. (Requirement 12)
M12. If there is an instance where there is a disagreement on a derived limit, the Reliability
Coordinator, Transmission Operator, Balancing Authority, Generator Operator, Load-serving
Entity, Purchasing-selling Entity and Transmission Service Provider involved in the
disagreement shall have and provide upon request evidence that could include, but is not
limited to, operator logs, voice recordings, electronic communications or equivalent evidence
that will be used to determine if it operated to the most limiting parameter. (Part 2 of
Requirement 13)
M13. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, procedural documents, operator logs, voice recordings or transcripts of
voice recordings, electronic communications or equivalent evidence that will be used to
confirm that it provided SOL and IROL information to Transmission Service Providers within
its Reliability Coordinator Area. (Requirement 14, Part 1)
M14. The Transmission Service Providers shall have and provide upon request evidence that could
include, but is not limited to, procedural documents, operator logs, voice recordings or
transcripts of voice recordings, electronic communications or equivalent evidence that will be
used to confirm that it respected the SOLs or IROLs in accordance with filed tariffs and
regional Total Transfer Calculation and Available Transfer Calculation
processes.(Requirement 14 Part 2)
M15. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings,
electronic communications or equivalent evidence that will be used to confirm that it issued
alerts when it foresaw a transmission problem (such as an SOL or IROL violation, loss of
reactive reserves, etc.) within its Reliability Coordinator Area, to all impacted Transmission
Operators and Balancing Authorities in its Reliability Coordinator Area as specified in
Requirement 15 Part 1.
M16. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings,
electronic communications or equivalent evidence that will be used to confirm that upon
receiving information such as an SOL or IROL violation, loss of reactive reserves, etc. it
disseminated the information to its impacted Transmission Operators and Balancing
Authorities as specified in Requirement 15 Part 2.
M17. The Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings,
electronic communications or equivalent evidence that will be used to confirm that it notified
all impacted Transmission Operators, Balancing Authorities and Reliability Coordinators when
a transmission problem has been mitigated. (Requirement 15 Part 3)
D. Compliance
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 5 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
For Measures 1 and 11, each Reliability Coordinator shall have its current in-force
documents as evidence.
For Measures 2–10 and Measure 13, and Measures 15 through 16, the Reliability
Coordinator shall keep 90 days of historical data (evidence).
For Measure 8, the Transmission Operator and Balancing Authority shall keep 90 days of
historical data (evidence).
For Measure 12, the Reliability Coordinator, Transmission Operator, Balancing
Authority, and Transmission Service Provider shall keep 90 days of historical data
(evidence).
For Measure 14, the Transmission Service Provider shall keep 90 days of historical data
(evidence).
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year, whichever is
longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 6 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
2.
Levels of Non-Compliance for a Transmission Operator, Balancing Authority, Generator
Operator, Load-serving Entity, Purchasing-selling Entity and Transmission Service
Provider
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following
requirements that is in violation:
3.
2.4.1
Did not follow the Reliability Coordinator’s directives in accordance with R8
Part 2).
2.4.2
Did not operate to the most limiting parameter when a difference in derived
limits existed. (R13 Part 2)
Levels of Non-Compliance for a Reliability Coordinator:
3.1. Level 1: Not applicable.
3.2. Level 2: Did not make Interchange Transaction information available to all other
Reliability Coordinators in the Interconnection. (Requirement 2)
3.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the following
requirements that is in violation:
3.3.1
Did not communicate to each of its Balancing Authorities and Transmission
Operators to make them aware of GMD forecast information or did not assist in
the development of any required response plans to a predicted GMD.
(Requirement 6)
3.3.2
Did not disseminate information within its Reliability Coordinator Area.
(Requirement 7)
3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following
requirements that is in violation:
3.4.1
Does not meet one or more of the requirements as specified in requirement 1
(Requirements 1.1 through R1.9)
3.4.2
Did not make Interchange Transaction information available to all other
Reliability Coordinators. (Requirement 2)
3.4.3
Did not initiate control actions or emergency procedures to relieve an IROL
violation without delay, and no longer than 30 minutes. (Requirement 3 Part 2
and Requirement 5)
3.4.4
Did not direct the Balancing Authorities in the Reliability Coordinator Area to
arrange for assistance from neighboring Balancing Authorities. (Requirement 4
Part 2)
3.4.5
Did not monitor the system frequency or each of its Balancing Authorities
performance or did not direct rebalancing to return to DCS and CPS compliance.
(Requirement 8 Part 1)
3.4.6
Did not coordinate with Transmission Operators, Balancing Authorities, and
Generator Operators as needed to develop and implement action plans to mitigate
potential or actual SOL, IROL, CPS, or DCS violations. (Requirement 9)
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 7 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
3.4.7
When it identified a source of large Area Control Errors, it did not initiate
corrective actions with the appropriate Balancing Authority if the problem was
inside its Reliability Coordinator Area. (Requirement 11 part 1)
3.4.8
Did not provide evidence that it was aware of the impact of the operation of a
Special Protection System on inter-area flows. (Requirement 12)
3.4.9
Did not operate to the most limiting parameter when a difference in derived
limits existed. (Requirement 13 Part 2)
3.4.10 Did not provide Transmission Service Providers with SOLs or IROLs (within the
Reliability Coordinator’s wide-area view ) (Requirement 14 Part 1)
3.4.11 Did not issue alerts when it foresaw a transmission problem (such as an SOL or
IROL violation, loss of reactive reserves, etc.) within its Reliability Coordinator
Area. (Requirement 15)
4.
Levels of Non-Compliance for a Transmission Service Provider
4.1. Level 1: Not applicable.
4.2. Level 2: Not applicable.
4.3. Level 3: Not applicable.
4.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the following
requirements that is in violation:
4.4.1
Did not operate to the most limiting parameter when a difference in derived
limits existed. (R13 Part 2)
4.4.2
Did not respect the SOLs or IROLs in accordance with filed tariffs and regional
Total Transfer Calculation and Available Transfer Calculation
processes.(Requirement 14 Part 2)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
February 2,
2006
Approved by Board of Trustees
Revised
2
August 31,
2006
Added three items that were inadvertently
left out to “Applicability” section:
4.5 Generator Operators.
4.6 Load-Serving Entities.
4.7 Purchasing-Selling Entities
Errata
2
November 1,
2006
Approved by Board of Trustees
Revised
2
June 26, 2007
Approved by FERC:
Revised
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 8 of 9
Standard IRO-005-X2 — Reliability Coordination — Current Day Operations
Missing Measures and Compliance
Elements
X
TBD
Modified R9 to include the Generator
Interconnection Facility.
Added a new Requirement R13
Approved by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Addition
Page 9 of 9
Standard MOD-010-X0 — Steady-State Data for Transmission System Modeling and Simulation
A. Introduction
1.
Title:
Steady-State Data for Modeling and Simulation of the Interconnected
Transmission System
2.
Number:
3.
Purpose:
To establish consistent data requirements, reporting procedures, and system
models to be used in the analysis of the reliability of the Interconnected Transmission Systems.
4.
Applicability:
MOD-010-X0
4.1. Transmission Owners specified in the data requirements and reporting procedures of
MOD-011-0_R1
4.2. Transmission Planners specified in the data requirements and reporting procedures of
MOD-011-0_R1
4.3. Generator Owners specified in the data requirements and reporting procedures of MOD011-0_R1
4.4. Resource Planners specified in the data requirements and reporting procedures of MOD011-0_R1
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
The Transmission Owners, Transmission Planners Generator Owners (for plant and Generator
Interconnection Facility), and Resource Planners (specified in the data requirements and
reporting procedures of MOD-011-0_R1) shall provide appropriate equipment characteristics,
system data, and existing and future Interchange Schedules in compliance with its respective
Interconnection Regional steady-state modeling and simulation data requirements and
reporting procedures as defined in Reliability Standard MOD-011-0_R1.
R2.
The Transmission Owners, Transmission Planners, Generator Owners (for plant and Generator
Interconnection Facility), and Resource Planners (specified in the data requirements and
reporting procedures of MOD-011-0_R1) shall provide this steady-state modeling and
simulation data to the Regional Reliability Organizations, NERC, and those entities specified
within Reliability Standard MOD-011-0_R1. If no schedule exists, then these entities shall
provide the data on request (30 calendar days).
C. Measures
M1. The Transmission Owner, Transmission Planner, Generator Owner, and Resource Planner,
(specified in the data requirements and reporting procedures of MOD-011-0_R1) shall have
evidence that it provided equipment characteristics, system data, and Interchange Schedules for
steady-state modeling and simulation to the Regional Reliability Organizations and NERC as
specified in Standard MOD-010-0_R1 and MOD-010-0_R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 2
Standard MOD-010-X0 — Steady-State Data for Transmission System Modeling and Simulation
As specified within the applicable reporting procedures (Reliability Standard MOD-0110_R2-M1). If no schedule exists, then on request (30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Steady-state data was provided, but was incomplete in one of the seven
areas identified in Reliability Standard MOD-011-0_R1.
2.2. Level 2:
Not applicable.
2.3. Level 3:
Steady-state data was provided, but was incomplete in two or more of the
seven areas identified in Reliability Standard MOD-011-0_R1.
2.4. Level 4:
Steady-state data was not provided.
E. Regional Differences
1.None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
X
TBD
Modified R1 and R2 to include plant and
Generator Interconnection Facility
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 2
Standard MOD-012-X0 — Dynamics Data for Transmission System Modeling and Simulation
A. Introduction
1.
Title:
Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System.
2.
Number:
3.
Purpose:
To establish consistent data requirements, reporting procedures, and system
models to be used in the analysis of the reliability of the interconnected transmission systems.
4.
Applicability:
MOD-012-X0
4.1. Transmission Owners specified in the data requirements and reporting procedures of
MOD-013-0_R1
4.2. Transmission Planners specified in the data requirements and reporting procedures of
MOD-013-0_R1
4.3. Generator Owners specified in the data requirements and reporting procedures of MOD013-0_R1
4.4. Resource Planners specified in the data requirements and reporting procedures of MOD013-0_R1
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
The Transmission Owners, Transmission Planners, Generator Owners (for plant and Generator
Interconnection Facility), and Resource Planners (specified in the data requirements and
reporting procedures of MOD-013-0_R1) shall provide appropriate equipment characteristics
and system data in compliance with the respective Interconnection-wide Regional dynamics
system modeling and simulation data requirements and reporting procedures as defined in
Reliability Standard MOD-013-0_R1.
R2.
The Transmission Owners, Transmission Planners, Generator Owners (for plant and Generator
Interconnection Facility), and Resource Planners (specified in the data requirements and
reporting procedures of MOD-013-0_R1) shall provide dynamics system modeling and
simulation data to its Regional Reliability Organization(s), NERC, and those entities specified
within the applicable reporting procedures identified in Reliability Standard MOD-013-0_R1.
If no schedule exists, then these entities shall provide data on request (30 calendar days).
C. Measures
M1. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-013-0_R1) shall each
have evidence that it provided equipment characteristics and system data for dynamics system
modeling and simulation in accordance with Reliability Standard MOD-012-0_R1 and
Reliability Standard MOD-012-0_R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 2
Standard MOD-012-X0 — Dynamics Data for Transmission System Modeling and Simulation
1.2. Compliance Monitoring Period and Reset Timeframe
As specified within the applicable reporting procedures (Reliability Standard MOD013-0). If no schedule exists, then on request (30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Dynamics data was provided, but was incomplete in one of the four areas
identified in Reliability Standard MOD-013-0_R1.
2.2. Level 2:
Not Applicable.
2.3. Level 3:
Dynamics data was provided, but was incomplete in two or more of the four
areas identified in Reliability Standard MOD-013-0_R1.
2.4. Level 4:
Dynamics data was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
September 16, 2005
Changed references to MOD-013-0 R4
to MOD-013-0 R1 in Applicability,
Requirements, and Measures (4 in all).
Errata
X
TBD
Modified R1 and R2 to include plant
and Generator Interconnection Facility
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 2
Standard PER-001-X0 — Operating Personnel Responsibility and Authority
A. Introduction
1.
Title:
Operating Personnel Responsibility and Authority
2.
Number:
PER-001-X0
3.
Purpose:
Transmission Operator and Balancing Authority operating personnel must have
the responsibility and authority to implement real-time actions to ensure the stable and reliable
operation of the Bulk Electric System.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Generator Operators.
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
Each Transmission Operator and Balancing Authority shall provide operating personnel with
the responsibility and authority to implement real-time actions to ensure the stable and reliable
operation of the Bulk Electric System.
R2.
Each Generator Operator shall provide operating personnel with the responsibility and
authority to implement real-time actions to ensure the stable and reliable operation of the
Generation Facility and Generation Interconnection Facility, and the responsibility and
authority to follow the directives of reliability authorities including the Transmission Operator
and Balancing Authority.
C. Measures
M1. The Transmission Operator and Balancing Authority provide documentation that operating
personnel have the responsibility and authority to implement real-time actions to ensure the
stable and reliable operation of the Bulk Electric System. These responsibilities and authorities
are understood by the operating personnel. Documentation shall include:
M1.1
A written current job description that states in clear and unambiguous language the
responsibilities and authorities of each operating position of a Transmission Operator
and Balancing Authority. The position description identifies personnel subject to the
authority of the Transmission Operator and Balancing Authority.
M1.2
The current job description is readily accessible in the control room environment to all
operating personnel.
M1.3
A written current job description that states operating personnel are responsible for
complying with the NERC reliability standards.
M1.4
Written operating procedures that state that, during normal and emergency conditions,
operating personnel have the authority to take or direct timely and appropriate realtime actions. Such actions shall include shedding of firm load to prevent or alleviate
System Operating Limit Interconnection or Reliability Operating Limit violations.
These actions are performed without obtaining approval from higher-level personnel
within the Transmission Operator or Balancing Authority.
D. Compliance
1.
Compliance Monitoring Process
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 2
Standard PER-001-X0 — Operating Personnel Responsibility and Authority
Periodic Review: An on-site review including interviews with Transmission Operator and
Balancing Authority operating personnel and document verification will be conducted every
three years. The job description identifying operating personnel authorities and responsibilities
will be reviewed, as will the written operating procedures or other documents delineating the
authority of the operating personnel to take actions necessary to maintain the reliability of the
Bulk Electric System during normal and emergency conditions.
1.1. Compliance Monitoring Responsibility
Self-certification: The Transmission Operator and Balancing Authority shall annually
complete a self-certification form developed by the Regional Reliability Organization
based on measures M1.1 to M1.4.
1.2. Compliance Monitoring Period and Reset Timeframe
One calendar year.
1.3. Data Retention
Permanent.
1.4. Additional Compliance Information
2.
Levels of Non-Compliance
2.1. Level 1:
The Transmission Operator or Balancing Authority has written
documentation that includes three of the four items in M1.
2.2. Level 2:
The Transmission Operator or Balancing Authority has written
documentation that includes two of the four items in M1.
2.3. Level 3:
The Transmission Operator or Balancing Authority has written
documentation that includes one of the four items in M1.
2.4. Level 4:
The Transmission Operator or Balancing Authority has written
documentation that includes none of the items in M1, or the personnel interviews indicate
Transmission Operator or Balancing Authority do not have the required authority.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
X
TBD
Added new Requirement R2
Added Generator Operators to the
Applicability Section
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 2
Standard PER-002-X0 — Operating Personnel Training
A. Introduction
1.
Title:
Operating Personnel Training
2.
Number:
PER-002-X0
3.
Purpose:
Each Transmission Operator and Balancing Authority must provide their
personnel with a coordinated training program that will ensure reliable system operation.
4.
Applicability
4.1. Balancing Authority.
4.2. Transmission Operator.
4.3. Generator Operator.
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
Each Transmission Operator, Generator Operator, and Balancing Authority shall be staffed
with adequately trained operating personnel.
R2.
Each Transmission Operator and Balancing Authority shall have a training program for all
operating personnel that are in:
R3.
R2.1.
Positions that have the primary responsibility, either directly or through
communications with others, for the real-time operation of the interconnected Bulk
Electric System.
R2.2.
Positions directly responsible for complying with NERC standards.
Each Generator Operator shall implement an initial and continuing training program for all
operating personnel that are responsible for operating the Generator Interconnection Facility
that verifies the personnel’s ability and understanding to operate the equipment in a reliable
manner.
R3.R4.
For personnel identified in Requirement R2, the Transmission Operator and
Balancing Authority shall provide a training program meeting the following criteria:
R3.1.R4.1. A set of training program objectives must be defined, based on NERC and
Regional Reliability Organization standards, entity operating procedures, and
applicable regulatory requirements. These objectives shall reference the knowledge
and competencies needed to apply those standards, procedures, and requirements to
normal, emergency, and restoration conditions for the Transmission Operator and
Balancing Authority operating positions.
R3.2.R4.2. The training program must include a plan for the initial and continuing training
of Transmission Operator and Balancing Authority operating personnel. That plan
shall address knowledge and competencies required for reliable system operations.
R3.3.R4.3. The training program must include training time for all Transmission Operator
and Balancing Authority operating personnel to ensure their operating proficiency.
R3.4.R4.4. Training staff must be identified, and the staff must be competent in both
knowledge of system operations and instructional capabilities.
For personnel identified in Requirement R2, each Transmission Operator and
R4.R5.
Balancing Authority shall provide its operating personnel at least five days per year of training
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 3
Standard PER-002-X0 — Operating Personnel Training
and drills using realistic simulations of system emergencies, in addition to other training
required to maintain qualified operating personnel.
C. Measures
M1. The Transmission Operator and Balancing Authority operating personnel training program
shall be reviewed to ensure that it is designed to promote reliable system operations.
D. Compliance
1.
Compliance Monitoring Process
Periodic Review: The Regional Reliability Organization will conduct an on-site review of the
Transmission Operator and Balancing Authority operating personnel training program every
three years. The operating personnel training records will be reviewed and assessed compared
to the program curriculum.
1.1. Compliance Monitoring Responsibility
Self-certification: The Transmission Operator and Balancing Authority will annually
provide a self-certification based on Requirements R1 through R4.
1.2. Compliance Monitoring Period and Reset Timeframe
One calendar year.
1.3. Data Retention
Three years.
1.4. Additional Compliance Information
Not specified.
2.
Levels of Non-Compliance
2.1. Level 1:
N/A.
2.2. Level 2:
The Transmission Operator or Balancing Authority operating personnel
training program does not address all elements of Requirement R3.
2.3. Level 3:
The Transmission Operator or Balancing Authority operating personnel
training program does not address Requirement R4.
2.4. Level 4:
A Transmission Operator or Balancing Authority has not provided a training
program for its operating personnel.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Proposed Effective Date
Errata
X
TBD
Modified R1 and the Applicability Section
to include Generator Operator
Added new Requirement R3
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 3
Standard PER-002-X0 — Operating Personnel Training
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
3 of 3
Standard PRC-001-X1 — System Protection Coordination
A. Introduction
1.
Title:
System Protection Coordination
2.
Number:
PRC-001-X1
3.
Purpose:
To ensure system protection is coordinated among operating entities.
4.
Applicability
4.1. Balancing Authorities
4.2. Transmission Operators
4.3. Generator Operators
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
Each Transmission Operator, Balancing Authority, and Generator Operator shall be
familiar with the purpose and limitations of protection system schemes applied in its
area, including those for the Generator Interconnection Facility.
R2.
Each Generator Operator and Transmission Operator shall notify reliability entities of
relay or equipment failures, including those for the Generator Interconnection Facility,
as follows:
R3.
R4.
R2.1.
If a protective relay or equipment failure reduces system reliability, the
Generator Operator shall notify its Transmission Operator and Host Balancing
Authority. The Generator Operator shall take corrective action as soon as
possible.
R2.2.
If a protective relay or equipment failure reduces system reliability, the
Transmission Operator shall notify its Reliability Coordinator and affected
Transmission Operators and Balancing Authorities. The Transmission
Operator shall take corrective action as soon as possible.
A Generator Operator or Transmission Operator shall coordinate new protective
systems and changes, including those for the Generator Interconnection Facility, as
follows.
R3.1.
Each Generator Operator shall coordinate all new protective systems and all
protective system changes, including those for the Generator Interconnection
Facility, with its Transmission Operator and Host Balancing Authority.
R3.2.
Each Transmission Operator shall coordinate all new protective systems and
all protective system changes with neighboring Transmission Operators and
Balancing Authorities.
Each Transmission Operator shall coordinate protection systems on major transmission
lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.
Adopted by Board of Trustees: November 1, 2007TBD
Effective Date: January 1, 2007TBD
Page 1 o
Standard PRC-001-X1 — System Protection Coordination
R5.
R6.
A Generator Operator or Transmission Operator shall coordinate changes in
generation, transmission, load or operating conditions, including those for the
Generator Interconnection Facility, that could require changes in the protection systems
of others:
R5.1.
Each Generator Operator shall notify its Transmission Operator in advance of
changes in generation or operating conditions, including those for the
Generator Interconnection Facility, that could require changes in the
Transmission Operator’s protection systems.
R5.2.
Each Transmission Operator shall notify neighboring Transmission Operators
in advance of changes in generation, transmission, load, or operating
conditions that could require changes in the other Transmission Operators’
protection systems.
Each Transmission Operator and Balancing Authority shall monitor the status of each
Special Protection System in their area, and shall notify affected Transmission
Operators and Balancing Authorities of each change in status.
C. Measures
M1. Each Generator Operator and Transmission Operator shall have and provide upon
request evidence that could include but is not limited to, revised fault analysis study,
letters of agreement on settings, notifications of changes, or other equivalent evidence
that will be used to confirm that there was coordination of new protective systems or
changes as noted in Requirements 3, 3.1, and 3.2.
M2. Each Transmission Operator and Balancing Authority shall have and provide upon
request evidence that could include but is not limited to, documentation, electronic
logs, computer printouts, or computer demonstration or other equivalent evidence that
will be used to confirm that it monitors the Special Protection Systems in its area.
(Requirement 6 Part 1)
M3. Each Transmission Operator and Balancing Authority shall have and provide upon
request evidence that could include but is not limited to, operator logs, phone records,
electronic-notifications or other equivalent evidence that will be used to confirm that it
notified affected Transmission Operator and Balancing Authorities of changes in status
of one of its Special Protection Systems. (Requirement 6 Part 2)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
Adopted by Board of Trustees: November 1, 2007TBD
Effective Date: January 1, 2007TBD
Page 2 o
Standard PRC-001-X1 — System Protection Coordination
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
Each Generator Operator and Transmission Operator shall have current, in-force
documents available as evidence of compliance for Measure 1.
Each Transmission Operator and Balancing Authority shall keep 90 days of
historical data (evidence) for Measures 2 and 3.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all requested
and submitted subsequent compliance records.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance for Generator Operators:
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: Failed to provide evidence of coordination when installing new
protective systems and all protective system changes with its Transmission
Operator and Host Balancing Authority as specified in R3.1.
3.
Levels of Non-Compliance for Transmission Operators:
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
Adopted by Board of Trustees: November 1, 2007TBD
Effective Date: January 1, 2007TBD
Page 3 o
Standard PRC-001-X1 — System Protection Coordination
3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
3.4.1
Failed to provide evidence of coordination when installing new protective
systems and all protective system changes with neighboring Transmission
Operators and Balancing Authorities as specified in R3.2.
3.4.2
Did not monitor the status of each Special Protection System, or did not
notify affected Transmission Operators, Balancing Authorities of changes
in special protection status as specified in R6.
Levels of Non-Compliance for Balancing Authorities:
4.
4.1. Level 1: Not applicable.
4.2. Level 2: Not applicable.
4.3. Level 3: Not applicable.
4.4. Level 4: Did not monitor the status of each Special Protection System, or did not
notify affected Transmission Operators, Balancing Authorities of changes in
special protection status as specified in R6.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
0
August 25,
2005
Fixed Standard number in Introduction
from PRC-001-1 to PRC-001-0
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
X
TBD
Modified R1, R2, R3, R3.1, R5, and
R5.1 to include the Generator
Interconnection Facility.
Addition
Adopted by Board of Trustees: November 1, 2007TBD
Effective Date: January 1, 2007TBD
Page 4 o
Standard PRC-004-X1 — Analysis and Mitigation of Transmission and Generation Protection
System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-X1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
Effective Date:
August 1, 2006 TBD
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Reliability Organization’s procedures developed for Reliability
Standard PRC-003 Requirement 1.
R2.
The Generator Owner shall analyze its generator Protection System Misoperations, including
those for the Generator Interconnection Facility, and shall develop and implement a Corrective
Action Plan to avoid future Misoperations of a similar nature according to the Regional
Reliability Organization’s procedures developed for PRC-003 R1.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Reliability Organization,
documentation of its Misoperations analyses and Corrective Action Plans according to the
Regional Reliability Organization’s procedures developed for PRC-003 R1.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Reliability Organization procedures developed for PRC-003
R1.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Reliability Organization’s procedures developed for PRC-003
R1.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Reliability Organization procedures developed for PRC-003 R1.
D. Compliance
1.
Compliance Monitoring Process
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: August 1, 2006TBD
1 of 3
Standard PRC-004-X1 — Analysis and Mitigation of Transmission and Generation Protection
System Misoperations
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation Protection System shall each
retain data on its Protection System Misoperations and each accompanying Corrective
Action Plan until the Corrective Action Plan has been executed or for 12 months,
whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Levels of Non-Compliance for Transmission Owners and Distribution Providers that own
a Transmission Protection System:
2.1. Level 1:
Documentation of Misoperations is complete according to PRC-004 R1, but
documentation of Corrective Action Plans is incomplete.
2.2. Level 2:
Documentation of Misoperations is incomplete according to PRC-004 R1
and documentation of Corrective Action Plans is incomplete.
2.3. Level 3:
Documentation of Misoperations is incomplete according to PRC-004 R1
and there are no associated Corrective Action Plans.
2.4. Level 4:
Misoperations have not been analyzed and documentation has not been
provided to the Regional Reliability Organization according to Requirement 3.
3.
Levels of Non-Compliance for Generator Owners
3.1. Level 1:
Documentation of Misoperations is complete according to PRC-004 R2, but
documentation of Corrective Action Plans is incomplete.
3.2. Level 2:
Documentation of Misoperations is incomplete according to PRC-004 R2
and documentation of Corrective Action Plans is incomplete.
3.3. Level 3:
Documentation of Misoperations is incomplete according to PRC-004 R2
and there are no associated Corrective Action Plans.
3.4. Level 4:
Misoperations have not been analyzed and documentation has not been
provided to the Regional Reliability Organization according to R3.
E. Regional Differences
None identified.
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: August 1, 2006TBD
2 of 3
Standard PRC-004-X1 — Analysis and Mitigation of Transmission and Generation Protection
System Misoperations
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/06
X
TBD
Modified R2 to include the Generator
Interconnection Facility
Addition
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: August 1, 2006TBD
3 of 3
Standard PRC-005-X1 — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-X1
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
May 1, 2006
B. Requirements
R1.
R2.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System, including those
for the Generator Interconnection Facility, shall have a Protection System maintenance and
testing program for Protection Systems that affect the reliability of the BES. The program shall
include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System, including those
for the Generator Interconnection Facility shall provide documentation of its Protection System
maintenance and testing program and the implementation of that program to its Regional
Reliability Organization on request (within 30 calendar days). The documentation of the
program implementation shall include:
R2.1.
Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System that affects the
reliability of the BES, shall have an associated Protection System maintenance and testing
program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System that affects the
reliability of the BES, shall have evidence it provided documentation of its associated
Protection System maintenance and testing program and the implementation of its program as
defined in Requirement 2.
D. Compliance
1.
Compliance Monitoring Process
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: May 1, 2006 TBD
1 of 3
Standard PRC-005-X1 — Transmission and Generation Protection System Maintenance and
Testing
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation Protection System,
shall retain evidence of the implementation of its Protection System maintenance and
testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation Protection System,
shall each demonstrate compliance through self-certification or audit (periodic, as part of
targeted monitoring or initiated by complaint or event), as determined by the Compliance
Monitor.
2.
Levels of Non-Compliance
2.1. Level 1: Documentation of the maintenance and testing program provided was
incomplete as required in R1, but records indicate maintenance and testing did occur
within the identified intervals for the portions of the program that were documented.
2.2. Level 2: Documentation of the maintenance and testing program provided was complete
as required in R1, but records indicate that maintenance and testing did not occur within
the defined intervals.
2.3. Level 3: Documentation of the maintenance and testing program provided was
incomplete, and records indicate implementation of the documented portions of the
maintenance and testing program did not occur within the identified intervals.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation,
was not provided.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash” (—).
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
01/20/05
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: May 1, 2006 TBD
2 of 3
Standard PRC-005-X1 — Transmission and Generation Protection System Maintenance and
Testing
in item D, 1.2.
X
TBD
Modified R1 and R2 to include the
Generator Interconnection Facility
Adopted by Board of Trustees: February 7, 2006 TBD
Effective Date: May 1, 2006 TBD
Additions
3 of 3
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
A. Introduction
1.
Title:
Reliability Responsibilities and Authorities
2.
Number:
TOP-001-X1
3.
Purpose:
To ensure reliability entities have clear decision-making authority and capabilities to
take appropriate actions or direct the actions of others to return the transmission system
to normal conditions during an emergency.
4.
Applicability
4.1. Balancing Authorities
4.2. Transmission Operators
4.3. Generator Operators
4.4. Distribution Providers
4.5. Load Serving Entities
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
Each Transmission Operator shall have the responsibility and clear decision-making
authority to take whatever actions are needed to ensure the reliability of its area and
shall exercise specific authority to alleviate operating emergencies.
R2.
Each Transmission Operator shall take immediate actions to alleviate operating
emergencies including curtailing transmission service or energy schedules, operating
equipment (e.g., generators, phase shifters, breakers), shedding firm load, etc.
R3.
Each Transmission Operator, Balancing Authority, and Generator Operator shall
comply with reliability directives issued by the Reliability Coordinator, and each
Balancing Authority and Generator Operator shall comply with reliability directives
issued by the Transmission Operator, unless such actions would violate safety,
equipment, regulatory or statutory requirements. Under these circumstances the
Transmission Operator, Balancing Authority or Generator Operator shall immediately
inform the Reliability Coordinator or Transmission Operator of the inability to perform
the directive so that the Reliability Coordinator or Transmission Operator can
implement alternate remedial actions.
R4.
Each Distribution Provider and Load Serving Entity shall comply with all reliability
directives issued by the Transmission Operator, including shedding firm load, unless
such actions would violate safety, equipment, regulatory or statutory requirements.
Under these circumstances, the Distribution Provider or Load Serving Entity shall
immediately inform the Transmission Operator of the inability to perform the directive
so that the Transmission Operator can implement alternate remedial actions.
R5.
Each Transmission Operator shall inform its Reliability Coordinator and any other
potentially affected Transmission Operators of real time or anticipated emergency
conditions, and take actions to avoid, when possible, or mitigate the emergency.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 1 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
R6.
Each Transmission Operator, Balancing Authority, and Generator Operator shall render
all available emergency assistance to others as requested, provided that the requesting
entity has implemented its comparable emergency procedures, unless such actions
would violate safety, equipment, or regulatory or statutory requirements.
R7.
Each Transmission Operator and Generator Operator shall not remove Bulk Electric
System facilities, including the Generator Interconnection Facility, from service if
removing those facilities would burden neighboring systems unless:
1.R7.1. For a generator outage, including the Generator Interconnection Facility, the
Generator Operator shall notify and coordinate with the Transmission
Operator. The Transmission Operator shall notify the Reliability Coordinator
and other affected Transmission Operators, and coordinate the impact of
removing the Bulk Electric System facility.
2.R7.2. For a transmission facility, the Transmission Operator shall notify and
coordinate with its Reliability Coordinator. The Transmission Operator shall
notify other affected Transmission Operators, and coordinate the impact of
removing the Bulk Electric System facility.
3.R7.3. When time does not permit such notifications and coordination, or when
immediate action is required to prevent a hazard to the public, lengthy
customer service interruption, or damage to facilities, the Generator Operator
shall notify the Transmission Operator, and the Transmission Operator shall
notify its Reliability Coordinator and adjacent Transmission Operators, at the
earliest possible time.
R8.
During a system emergency, the Balancing Authority and Transmission Operator shall
immediately take action to restore the Real and Reactive Power Balance. If the
Balancing Authority or Transmission Operator is unable to restore Real and Reactive
Power Balance it shall request emergency assistance from the Reliability Coordinator.
If corrective action or emergency assistance is not adequate to mitigate the Real and
Reactive Power Balance, then the Reliability Coordinator, Balancing Authority, and
Transmission Operator shall implement firm load shedding.
R9.
The Generator Operator, in accord with the expectations defined by the Transmission
Operator, shall coordinate the operation of its Generator Interconnection Facility with
the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability with respect to the following:
Switching elements
Outage planning
Real-time or anticipated emergency conditions
Other conditions mutually agreed upon by the Generator Operator and
Transmission Operator
R10. The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve
Interconnection reliability.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 2 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
The Generator Operator shall take the action it deems appropriate to remove from
service the Generator Interconnection Facilities when safety is jeopardized or
equipment damage is imminent.
The Generator Operator shall notify the Transmission Operator as soon as
practical of the actions taken and the reasons therein.
C. Measures
M1. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to, signed agreements, an authority letter signed by an officer
of the company, or other equivalent evidence that will be used to confirm that it has the
authority, and has exercised the authority, to alleviate operating emergencies as
described in Requirement 1.
M2. If an operating emergency occurs the Transmission Operator that experienced the
emergency shall have and provide upon request evidence that could include, but is not
limited to, operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to determine if it took
immediate actions to alleviate the operating emergency including curtailing
transmission service or energy schedules, operating equipment (e.g., generators, phase
shifters, breakers), shedding firm load, etc. (Requirement 2)
M3. Each Transmission Operator, Balancing Authority, and Generator Operator shall have
and provide upon request evidence such as operator logs, voice recordings or
transcripts of voice recordings, electronic communications, or other equivalent
evidence that will be used to determine if it complied with its Reliability Coordinator’s
reliability directives. If the Transmission Operator, Balancing Authority or Generator
Operator did not comply with the directive because it would violate safety, equipment,
regulatory or statutory requirements, it shall provide evidence such as operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or other
equivalent evidence that it immediately informed the Reliability Coordinator of its
inability to perform the directive. (Requirement 3)
M4. Each Balancing Authority, Generator Operator, Distribution Provider and Load
Serving Entity shall have and provide upon request evidence such as operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or other
equivalent evidence that will be used to determine if it complied with its Transmission
Operator’s reliability directives. If the Balancing Authority, Generator Operator,
Distribution Provider and Load Serving Entity did not comply with the directive
because it would violate safety, equipment, regulatory or statutory requirements, it
shall provide evidence such as operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or other equivalent evidence that it
immediately informed the Transmission Operator of its inability to perform the
directive. (Requirements 3 and 4)
M5. The Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to, operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or other equivalent evidence that will be used
to determine if it informed its Reliability Coordinator and any other potentially affected
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 3 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
Transmission Operators of real time or anticipated emergency conditions, and took
actions to avoid, when possible, or to mitigate an emergency. (Requirement 5)
M6. The Transmission Operator, Balancing Authority, and Generator Operator shall each
have and provide upon request evidence that could include, but is not limited to,
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or other equivalent evidence that will be used to determine if it
rendered assistance to others as requested, provided that the requesting entity had
implemented its comparable emergency procedures, unless such actions would violate
safety, equipment, or regulatory or statutory requirements. (Requirement 6)
M7. The Transmission Operator and Generator Operator shall each have and provide upon
request evidence that could include, but is not limited to, operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or other
equivalent evidence that will be used to determine if it notified either their
Transmission Operator in the case of the Generator Operator, or other Transmission
Operators, and the Reliability Coordinator when it removed Bulk Electric System
facilities from service if removing those facilities would burden neighboring systems.
(Requirement 7)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
Each Transmission Operator shall have the current in-force document to show
that it has the responsibility and clear decision-making authority to take whatever
actions are needed to ensure the reliability of its area. (Measure 1)
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 4 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
Each Transmission Operator shall keep 90 days of historical data (evidence) for
Measures 1 through 7, including evidence of directives issued for Measures 3 and
4.
Each Balancing Authority shall keep 90 days of historical data (evidence) for
Measures 3, 4 and 6 including evidence of directives issued for Measures 3 and 4.
Each Generator Operator shall keep 90 days of historical data (evidence) for
Measures 3, 4, 6 and 7 including evidence of directives issued for Measures 3 and
4.
Each Distribution Provider and Load-serving Entity shall keep 90 days of
historical data (evidence) for Measure 4.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all
supporting compliance data
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance for a Balancing Authority:
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
3.
2.4.1
Did not comply with a Reliability Coordinator’s or Transmission
Operator’s reliability directive or did not immediately inform the
Reliability Coordinator or Transmission Operator of its inability to
perform that directive (R3)
2.4.2
Did not render emergency assistance to others as requested, in accordance
with R6.
Levels of Non-Compliance for a Transmission Operator
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 5 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
4.
3.4.1
Does not have the documented authority to act as specified in R1.
3.4.2
Does not have evidence it acted with the authority specified in R1.
3.4.3
Did not take immediate actions to alleviate operating emergencies as
specified in R2.
3.4.4
Did not comply with its Reliability Coordinator’s reliability directive or
did not immediately inform the Reliability Coordinator of its inability to
perform that directive, as specified in R3.
3.4.5
Did not inform its Reliability Coordinator and other potentially affected
Transmission Operators of real time or anticipated emergency conditions
as specified in R5.
3.4.6
Did not take actions to avoid, when possible, or to mitigate an emergency
as specified in R5.
3.4.7
Did not render emergency assistance to others as requested, as specified in
R6.
3.4.8
Removed Bulk Electric System facilities from service under conditions
other than those specified in R7.1, 7.2, and 7.3, and removing those
facilities burdened a neighbor system.
Levels of Non-Compliance for a Generator Operator:
4.1. Level 1: Not applicable.
4.2. Level 2: Not applicable.
4.3. Level 3: Not applicable.
4.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
5.
4.4.1
Did not comply with a Reliability Coordinator or Transmission Operator’s
reliability directive or did not immediately inform the Reliability
Coordinator or Transmission Operator of its inability to perform that
directive, as specified in R3.
4.4.2
Did not render all available emergency assistance to others as requested,
unless such actions would violate safety, equipment, or regulatory or
statutory requirements as specified in R6.
4.4.3
Removed Bulk Electric System facilities from service under conditions
other than those specified in R7.1, 7.2, and 7.3, and burdened a neighbor
system.
Levels of Non-Compliance for a Distribution Provider or Load Serving Entity
5.1. Level 1: Not applicable.
5.2. Level 2: Not applicable.
5.3. Level 3: Not applicable
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 6 of 7
Standard TOP-001-X1 — Reliability Responsibilities and Authorities
5.4. Level 4: Did not comply with a Transmission Operator’s reliability directive or
immediately inform the Transmission Operator of its inability to perform that
directive, as specified in R4.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
X
TBD
Modified R7 and R7.1 to include the
Generator Interconnection Facility
Added new Requirements R19 and,
R10, and R11.
Addition
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 7 of 7
Standard TOP-002-2X — Normal Operations Planning
A. Introduction
1.
Title:
Normal Operations Planning
2.
Number:
TOP-002-X2
3.
Purpose: Current operations plans and procedures are essential to being prepared for
reliable operations, including response for unplanned events.
4.
Applicability
4.1. Balancing Authority.
4.2. Transmission Operator.
4.3. Generator Operator.
4.4. Load Serving Entity.
4.5. Transmission Service Provider.
5.
Effective Date:
January 1, 2007TBD
Six months after effective date of VAR-001-1.
B. Requirements
R1.
Each Balancing Authority and Transmission Operator shall maintain a set of current
plans that are designed to evaluate options and set procedures for reliable operation
through a reasonable future time period. In addition, each Balancing Authority and
Transmission Operator shall be responsible for using available personnel and system
equipment to implement these plans to ensure that interconnected system reliability
will be maintained.
R2.
Each Balancing Authority and Transmission Operator shall ensure its operating
personnel participate in the system planning and design study processes, so that these
studies contain the operating personnel perspective and system operating personnel are
aware of the planning purpose.
R3.
Each Load Serving Entity and Generator Operator shall coordinate (where
confidentiality agreements allow) its current-day, next-day, and seasonal operations,
including for the Generator Interconnection Facility, with its Host Balancing Authority
and Transmission Service Provider. Each Balancing Authority and Transmission
Service Provider shall coordinate its current-day, next-day, and seasonal operations
with its Transmission Operator.
R4.
Each Balancing Authority and Transmission Operator shall coordinate (where
confidentiality agreements allow) its current-day, next-day, and seasonal planning and
operations with neighboring Balancing Authorities and Transmission Operators and
with its Reliability Coordinator, so that normal Interconnection operation will proceed
in an orderly and consistent manner.
R5.
Each Balancing Authority and Transmission Operator shall plan to meet scheduled
system configuration, generation dispatch, interchange scheduling and demand
patterns.
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 1 of 7
Standard TOP-002-2X — Normal Operations Planning
R6.
Each Balancing Authority and Transmission Operator shall plan to meet unscheduled
changes in system configuration and generation dispatch (at a minimum N-1
Contingency planning) in accordance with NERC, Regional Reliability Organization,
subregional, and local reliability requirements.
R7.
Each Balancing Authority shall plan to meet capacity and energy reserve requirements,
including the deliverability/capability for any single Contingency.
R8.
Each Balancing Authority shall plan to meet voltage and/or reactive limits, including
the deliverability/capability for any single contingency.
R9.
Each Balancing Authority shall plan to meet Interchange Schedules and ramps.
R10. Each Balancing Authority and Transmission Operator shall plan to meet all System
Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs).
R11. The Transmission Operator shall perform seasonal, next-day, and current-day Bulk
Electric System studies to determine SOLs. Neighboring Transmission Operators shall
utilize identical SOLs for common facilities. The Transmission Operator shall update
these Bulk Electric System studies as necessary to reflect current system conditions;
and shall make the results of Bulk Electric System studies available to the
Transmission Operators, Balancing Authorities (subject to confidentiality
requirements), and to its Reliability Coordinator.
R12. The Transmission Service Provider shall include known SOLs or IROLs within its area
and neighboring areas in the determination of transfer capabilities, in accordance with
filed tariffs and/or regional Total Transfer Capability and Available Transfer Capability
calculation processes.
R13. At the request of the Balancing Authority or Transmission Operator, a Generator
Operator shall perform generating real and reactive capability verification that shall
include, among other variables, weather, ambient air and water conditions, and fuel
quality and quantity, and provide the results to the Balancing Authority or
Transmission Operator operating personnel as requested.
R14. Generator Operators shall, without any intentional time delay, notify their Balancing
Authority and Transmission Operator of changes in capabilities and characteristics
including but not limited to:
R14.1. Changes in real and reactive output capabilities. (Retired August 1, 2007)
R14.1. Changes in real output capabilities. (Effective August 1, 2007)
R14.2. Automatic Voltage Regulator status and mode setting. (Retired August 1,
2007)
R14.2. Changes in Generator Interconnection Facility Status
R15. Generation Operators shall, at the request of the Balancing Authority or Transmission
Operator, provide a forecast of expected real power output to assist in operations
planning (e.g., a seven-day forecast of real output).
R16. Subject to standards of conduct and confidentiality agreements, Transmission
Operators shall, without any intentional time delay, notify their Reliability Coordinator
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 2 of 7
Standard TOP-002-2X — Normal Operations Planning
and Balancing Authority of changes in capabilities and characteristics including but not
limited to:
R16.1. Changes in transmission facility status.
R16.2. Changes in transmission facility rating.
R17. Balancing Authorities and Transmission Operators shall, without any intentional time
delay, communicate the information described in the requirements R1 to R16 above to
their Reliability Coordinator.
R18. Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line
identifiers when referring to transmission facilities of an interconnected network and
for the Generator Interconnection Facility.
R19. Each Balancing Authority and Transmission Operator shall maintain accurate computer
models utilized for analyzing and planning system operations.
C. Measures
M1. Each Balancing Authority and Transmission Operator shall have and provide upon
request evidence that could include, but is not limited to, documented planning
procedures, copies of current day plans, copies of seasonal operations plans, or other
equivalent evidence that will be used to confirm that it maintained a set of current
plans. (Requirement 1 Part 1).
M2. Each Balancing Authority and Transmission Operator shall have and provide upon
request evidence that could include, but is not limited to, copies of current day plans or
other equivalent evidence that will be used to confirm that its plans address
Requirements 5, 6, and 10.
M3. Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to, copies of current day plans or other equivalent evidence
that will be used to confirm that its plans address Requirements 7, 8, and 9.
M4. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to, its next-day, and current-day Bulk Electric System studies
used to determine SOLs or other equivalent evidence that will be used to confirm that
its studies reflect current system conditions. (Requirement 11 Part 1)
M5. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to, voice recordings or transcripts of voice recordings,
electronic communications, or other equivalent evidence that will be used to confirm
that the results of Bulk Electric System studies were made available to the
Transmission Operators, Balancing Authorities (subject to confidentiality
requirements), and to its Reliability Coordinator. (Requirement 11 Part 2)
M6. Each Generator Operator shall have and provide upon request evidence that, when
requested by either a Transmission Operator or Balancing Authority, it performed a
generating real and reactive capability verification and provided the results to the
requesting entity in accordance with Requirement 13.
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 3 of 7
Standard TOP-002-2X — Normal Operations Planning
M7. Each Generator Operator shall have and provide upon request evidence that could
include, but is not limited to, voice recordings or transcripts of voice recordings,
electronic communications, or other equivalent evidence that will be used to confirm
that without any intentional time delay, it notified its Balancing Authority and
Transmission Operator of changes in real and reactive capabilities and AVR status.
(Requirement 14)
M8. Each Generator Operator shall have and provide upon request evidence that could
include, but is not limited to, voice recordings or transcripts of voice recordings,
electronic communications, or other equivalent evidence that will be used to confirm
that, on request, it provided a forecast of expected real power output to assist in
operations planning. (Requirement 15)
M9. Each Transmission Operators shall have and provide upon request evidence that could
include, but is not limited to, voice recordings or transcripts of voice recordings,
electronic communications, or other equivalent evidence that will be used to confirm
that, without any intentional time delay, it notified its Balancing Authority and
Reliability Coordinator of changes in capabilities and characteristics. (Requirement16)
M10. Each Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider and Load Serving Entity shall have and provide upon request
evidence that could include, but is not limited to, a list of interconnected transmission
facilities and their line identifiers at each end or other equivalent evidence that will be
used to confirm that it used uniform line identifiers when referring to transmission
facilities of an interconnected network. (Requirement 18)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 calendar days to prepare for the investigation. An entity may
request an extension of the preparation period and the extension will be
considered by the Compliance Monitor on a case-by-case basis.)
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 4 of 7
Standard TOP-002-2X — Normal Operations Planning
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
For Measures 1 and 2, each Transmission Operator shall have its current plans
and a rolling 6 months of historical records (evidence).
For Measures 1, 2, and 3 each Balancing Authority shall have its current plans
and a rolling 6 months of historical records (evidence).
For Measure 4, each Transmission Operator shall keep its current plans
(evidence).
For Measures 5 and 9, each Transmission Operator shall keep 90 days of
historical data (evidence).
For Measures 6, 7 and 8, each Generator Operator shall keep 90 days of historical
data (evidence).
For Measure 10, each Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, and Load-serving Entity shall have its
current list interconnected transmission facilities and their line identifiers at each
end or other equivalent evidence as evidence.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all
supporting compliance data
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance for Balancing Authorities:
2.1. Level 1: Did not use uniform line identifiers when referring to transmission
facilities of an interconnected network as specified in R18.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
3.
2.4.1
Did not maintain an updated set of current-day plans as specified in R1.
2.4.2
Plans did not meet one or more of the requirements specified in R5
through R10.
Levels of Non-Compliance for Transmission Operators
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 5 of 7
Standard TOP-002-2X — Normal Operations Planning
3.1. Level 1: Did not use uniform line identifiers when referring to transmission
facilities of an interconnected network as specified in R18.
3.2. Level 2: Not applicable.
3.3. Level 3: One or more of Bulk Electric System studies were not made available as
specified in R11.
3.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
4.
3.4.1
Did not maintain an updated set of current-day plans as specified in R1.
3.4.2
Plans did not meet one or more of the requirements in R5, R6, and R10.
3.4.3
Studies not updated to reflect current system conditions as specified in
R11.
3.4.4
Did not notify its Balancing Authority and Reliability Coordinator of
changes in capabilities and characteristics as specified in R16.
Levels of Non-Compliance for Generator Operators:
4.1. Level 1: Did not use uniform line identifiers when referring to transmission
facilities of an interconnected network as specified in R18.
4.2. Level 2: Not applicable.
4.3. Level 3: Not applicable.
4.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
5.
4.4.1
Did not verify and provide a generating real and reactive capability
verification and provide the results to the requesting entity as specified in
R13.
4.4.2
Did not notify its Balancing Authority and Transmission Operator of
changes in capabilities and characteristics as specified in R14.
4.4.3
Did not provide a forecast of expected real power output to assist in
operations planning as specified in R15.
Levels of Non-Compliance for Transmission Service Providers and Load-serving
Entities:
5.1. Level 1: Did not use uniform line identifiers when referring to transmission
facilities of an interconnected network as specified in R18.
5.2. Level 2: Not applicable.
5.3. Level 3: Not applicable.
5.4. Level 4: Not applicable.
E. Regional Differences
None identified.
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 6 of 7
Standard TOP-002-2X — Normal Operations Planning
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
2
June 14, 2007
Fixed typo in R11., (subject to …)
Errata
X
TBD
Modified R3 and R18 to include the
Generator Interconnection Facility and
added Requirement R14.3.
Addition
Adopted by Board of Trustees: November 1, 2006 TBD
Effective Date: January 1, 2007TBD
Page 7 of 7
Standard-TOP-003-X0 — Planned Outage Coordination
A. Introduction
1.
Title:
Planned Outage Coordination
2.
Number:
TOP-003-X0
3.
Purpose:
Scheduled generator and transmission outages that may affect the reliability of
interconnected operations must be planned and coordinated among Balancing Authorities,
Transmission Operators, and Reliability Coordinators.
4.
Applicability
4.1. Generator Operators.
4.2. Transmission Operators.
4.3. Balancing Authorities.
4.4. Reliability Coordinators.
5.
Effective Date:
April 1, 2005TBD
B. Requirements
R1.
Generator Operators and Transmission Operators shall provide planned outage information,
including information for the Generator Interconnection Facility.
R1.1.
Each Generator Operator shall provide outage information daily to its Transmission
Operator for scheduled generator outages planned for the next day (any foreseen
outage of a generator greater than 50 MW) or the Generator Interconnection Facility.
The Transmission Operator shall establish the outage reporting requirements.
R1.2.
Each Transmission Operator shall provide outage information daily to its Reliability
Coordinator, and to affected Balancing Authorities and Transmission Operators for
scheduled generator and bulk transmission outages planned for the next day (any
foreseen outage of a transmission line or transformer greater than 100 kV or generator
greater than 50 MW) that may collectively cause or contribute to an SOL or IROL
violation or a regional operating area limitation. The Reliability Coordinator shall
establish the outage reporting requirements.
R1.3.
Such information shall be available by 1200 Central Standard Time for the Eastern
Interconnection and 1200 Pacific Standard Time for the Western Interconnection.
R2.
Each Transmission Operator, Balancing Authority, and Generator Operator shall plan and
coordinate scheduled outages of system voltage regulating equipment, such as automatic
voltage regulators on generators, supplementary excitation control, synchronous condensers,
shunt and series capacitors, reactors, etc., among affected Balancing Authorities and
Transmission Operators as required.
R3.
Each Transmission Operator, Balancing Authority, and Generator Operator shall plan and
coordinate scheduled outages of telemetering and control equipment and associated
communication channels between the affected areas.
R4.
Each Reliability Coordinator shall resolve any scheduling of potential reliability conflicts.
C. Measures
M1. Evidence that the Generator Operator, Transmission Operator, Balancing Authority, and
Reliability Coordinator reported and coordinated scheduled outage information as indicated in
the requirements above.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
1 of 3
Standard-TOP-003-X0 — Planned Outage Coordination
D. Compliance
1.
Compliance Monitoring Process
Each Regional Reliability Organization shall conduct a review every three years to ensure that
each responsible entity has a process in place to provide planned generator and/or bulk
transmission outage information to their Reliability Coordinator, and with neighboring
Transmission Operators and Balancing Authorities.
Investigation: At the discretion of the Regional Reliability Organization or NERC, an
investigation may be initiated to review the planned outage process of a monitored entity due
to a complaint of non-compliance by another entity. Notification of an investigation must be
made by the Regional Reliability Organization to the entity being investigated as soon as
possible, but no later than 60 days after the event. The form and manner of the investigation
will be set by NERC and/or the Regional Reliability Organization.
1.1. Compliance Monitoring Responsibility
A Reliability Coordinator makes a request for an outage to “not be taken” because of a
reliability impact on the grid and the outage is still taken. The Reliability Coordinator
must provide all its documentation within three business days to the Regional Reliability
Organization. Each Regional Reliability Organization shall report compliance and
violations to NERC via the NERC Compliance Reporting process.
1.2. Compliance Monitoring Period and Reset Timeframe
One calendar year without a violation from the time of the violation.
1.3. Data Retention
One calendar year.
1.4. Additional Compliance Information
Not specified.
2.
Levels of Non-Compliance
2.1. Level 1:
Each entity responsible for reporting information under Requirements R1
and R3 has a process in place to provide information to their Reliability Coordinator but
does not have a process in place (where permitted by legal agreements) to provide this
information to the neighboring Balancing Authority or Transmission Operator.
2.2. Level 2:
N/A.
2.3. Level 3:
N/A.
2.4. Level 4:
There is no process in place to exchange outage information, or the entity
responsible for reporting information under Requirements R1 to R3 does not follow the
directives of the Reliability Coordinator to cancel or reschedule an outage.
E. Regional Differences
None identified.
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
2 of 3
Standard-TOP-003-X0 — Planned Outage Coordination
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
X
TBD
Modified R1 and R1.1 to include the
Generator Interconnection Facility
Addition
Adopted by NERC Board of Trustees: February 8, 2005TBD
Effective Date: April 1, 2005TBD
3 of 3
Standard TOP-004-X2 — Transmission Operations
A. Introduction
1.
Title:
Transmission Operations
2.
Number:
TOP-004-X2
3.
Purpose: To ensure that the transmission system is operated so that instability,
uncontrolled separation, or cascading outages will not occur as a result of the most severe
single Contingency and specified multiple Contingencies.
4.
Applicability:
4.1. Transmission Operators
5.
Proposed Effective Date:
Twelve months after BOT adoption of FAC-014TBD.
B. Requirements
R1.
Each Transmission Operator shall operate within the Interconnection Reliability Operating
Limits (IROLs) and System Operating Limits (SOLs).
R2.
Each Transmission Operator shall operate so that instability, uncontrolled separation, or
cascading outages will not occur as a result of the most severe single contingency.
R3.
Each Transmission Operator shall operate to protect against instability, uncontrolled
separation, or cascading outages resulting from multiple outages, as specified by its Reliability
Coordinator.
R4.
If a Transmission Operator enters an unknown operating state (i.e. any state for which valid
operating limits have not been determined), it will be considered to be in an emergency and
shall restore operations to respect proven reliable power system limits within 30 minutes.
R5.
Each Transmission Operator shall make every effort to remain connected to the
Interconnection. If the Transmission Operator determines that by remaining interconnected, it
is in imminent danger of violating an IROL or SOL, the Transmission Operator may take such
actions, as it deems necessary, to protect its area.
R6.
Transmission Operators, individually and jointly with other Transmission Operators, shall
develop, maintain, and implement formal policies and procedures to provide for transmission
reliability. These policies and procedures shall address the execution and coordination of
activities that impact inter- and intra-Regional reliability, including:
R7.
R6.1.
Monitoring and controlling voltage levels and real and reactive power flows.
R6.2.
Switching transmission elements.
R6.3.
Planned outages of transmission elements.
R6.4.
Responding to IROL and SOL violations.
The Generator Operator shall operate its Generator Interconnection Facility within its
applicable ratings.
C. Measures
M1. Each Transmission Operator that enters an unknown operating state for which valid limits
have not been determined, shall have and provide upon request evidence that could include,
but is not limited to, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, alarm program printouts, or other equivalent evidence that will
be used to determine if it restored operations to respect proven reliable power system limits
within 30 minutes as specified in Requirement 4.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: October 1, 2007TBD
Page 1 of 4
Standard TOP-004-X2 — Transmission Operations
M2. Each Transmission Operator shall have and provide upon request current policies and
procedures that address the execution and coordination of activities that impact inter- and
intra-Regional reliability for each of the topics listed in Requirements 6.1 through 6.6.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: October 1, 2007TBD
Page 2 of 4
Standard TOP-004-X2 — Transmission Operations
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
Each Transmission Operator shall keep 90 days of historical data for Measure 1.
Each Transmission Operator shall have current, in-force policies and procedures,
as evidence of compliance to Measure 2.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all
supporting compliance data
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance:
2.1. Level 1: Not applicable.
2.2. Level 2: Did not have formal policies and procedures to address one of the topics
listed in R6.1 through R6.4.
2.3. .Level 3: Did not have formal policies and procedures to address two of the topics
listed in R6.1 through R6.4.
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: October 1, 2007TBD
Page 3 of 4
Standard TOP-004-X2 — Transmission Operations
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
2.4.1
Did not restore operations to respect proven reliable power system limits
within 30 minutes as specified in R4.
2.4.2
Did not have formal policies and procedures to address three or all of the
topics listed in R6.1 through R6.4.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Added language from Missing Measures Revised
and Compliance Elements adopted by
Board of Trustees on November 1, 2006
2
December 19,
2007
Revised to reflect merging of both sets
of changes approved by BOT on
November 1, 2006 (Addition of
measures and compliance elements and
revisions to R3 and R6 with conforming
changes made as errata to Levels of
Non-compliance)
Revised
TBD
Added Requirement R7
Addition
X
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: October 1, 2007TBD
Errata
Page 4 of 4
Standard TOP-008-X1 — Response to Transmission Limit Violations
A. Introduction
1.
Title:
Response to Transmission Limit Violations
2.
Number:
TOP-008-X1
3.
Purpose: To ensure Transmission Operators take actions to mitigate SOL and IROL
violations.
4.
Applicability
4.1. Transmission Operators.
4.2. Generator Operators.
5.
Effective Date:
January 1, 2007TBD
B. Requirements
R1.
The Transmission Operator experiencing or contributing to an IROL or SOL violation
shall take immediate steps to relieve the condition, which may include shedding firm
load.
R2.
Each Transmission Operator shall operate to prevent the likelihood that a disturbance,
action, or inaction will result in an IROL or SOL violation in its area or another area of
the Interconnection. In instances where there is a difference in derived operating
limits, the Transmission Operator shall always operate the Bulk Electric System to the
most limiting parameter.
R3.
The Transmission Operator shall disconnect the affected facility if the overload on a
transmission facility or abnormal voltage or reactive condition persists and equipment
is endangered. In doing so, the Transmission Operator shall notify its Reliability
Coordinator and all neighboring Transmission Operators impacted by the
disconnection prior to switching, if time permits, otherwise, immediately thereafter.
R4.
The Transmission Operator shall have sufficient information and analysis tools to
determine the cause(s) of SOL violations. This analysis shall be conducted in all
operating timeframes. The Transmission Operator shall use the results of these
analyses to immediately mitigate the SOL violation.
R5.
The Generator Operator shall disconnect the Generator Interconnection Facility when
safety is jeopardized or if the overload or abnormal voltage or reactive condition
persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator
and Balancing Authority impacted by the disconnection prior to switching, if time
permits, otherwise, immediately thereafter.
C. Measures
M1. The Transmission Operator involved in an SOL or IROL violation shall have and
provide upon request evidence that could include, but is not limited to, operator logs,
voice recordings, electronic communications, alarm program printouts, or other
equivalent evidence that will be used to determine if it took immediate steps to relieve
the condition. (Requirement 1)
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 1 o
Standard TOP-008-X1 — Response to Transmission Limit Violations
M2. The Transmission Operator that disconnects an overloaded facility shall have and
provide upon request evidence that could include, but is not limited to, operator logs,
voice recordings, electronic communications, alarm program print outs, or other
equivalent evidence that will be used to determine if it disconnected an overloaded
facility in accordance with Requirement 3 Part 1
M3. The Transmission Operator that disconnects an overloaded facility shall have and
provide upon request evidence that could include, but is not limited to, operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or other
equivalent evidence that will be used to determine if it notified its Reliability
Coordinator and all neighboring Transmission Operators impacted by the
disconnection prior to switching, if time permitted, otherwise, immediately thereafter.
(Requirement 3 Part 2)
M4. The Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to, computer facilities documents, computer printouts,
training documents, copies of analysis program results, operator logs or other
equivalent evidence that will be used to confirm that it has sufficient information and
analysis tools to determine the cause(s) of SOL violations. (Requirement 4 Part 1)
M5. The Transmission Operator that violates an SOL shall have and provide upon request
evidence that could include, but is not limited to, operator logs, voice recordings or
transcripts of voice recordings, electronic communications, or other equivalent
evidence that will be used to confirm that it used the results of these analyses to
immediately mitigate the SOL violation. (Requirement 4 Part 3)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 2 o
Standard TOP-008-X1 — Response to Transmission Limit Violations
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
Each Transmission Operator shall keep 90 days of historical data (evidence) for
Measure 1, 2 and 3.
Each Transmission Operator shall have current documents as evidence of
compliance to Measures 4 and 5.
If an entity is found non-compliant the entity shall keep information related to the
noncompliance until found compliant or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor,
The Compliance Monitor shall keep the last periodic audit report and all requested
and submitted subsequent compliance data
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance for Transmission Operator
2.1. Level 1: Not applicable.
2.2. Level 2: Disconnected an overloaded facility as specified in R3 but did not notify
its Reliability Coordinator and all neighboring Transmission Operators impacted
by the disconnection prior to switching, or immediately thereafter.
2.3. Level 3: Not applicable.
2.4. Level 4: There shall be a separate Level 4 non-compliance, for every one of the
following requirements that is in violation:
2.4.1
Did not take immediate steps to relieve an IROL or SOL violation in
accordance with R1.
2.4.2
Did not disconnect an overloaded facility as specified in R3.
2.4.3
Does not have sufficient information and analysis tools to determine the
cause(s) of SOL violations. (R4 Part 1)
2.4.4
Did not use the results of analyses to immediately mitigate an SOL
violation. (R4 Part 3)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Change Tracking
Page 3 o
Standard TOP-008-X1 — Response to Transmission Limit Violations
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
X
TBD
Added new Requirement R5
Addition
Adopted by Board of Trustees: November 1, 2006TBD
Effective Date: January 1, 2007TBD
Page 4 o
Standard VAR-001-X1 — Voltage and Reactive Control
A.
B.
Introduction
1.
Title:
Voltage and Reactive Control
2.
Number:
VAR-001-X1
3.
Purpose: To ensure that voltage levels, reactive flows, and reactive resources are
monitored, controlled, and maintained within limits in real time to protect equipment and the
reliable operation of the Interconnection.
4.
Applicability:
4.1. Transmission Operators.
4.2. Purchasing-Selling Entities.
5.
Effective Date:
Requirements
R1. Each Transmission Operator, individually and jointly with other Transmission Operators,
shall ensure that formal policies and procedures are developed, maintained, and
implemented for monitoring and controlling voltage levels and Mvar flows within their
individual areas and with the areas of neighboring Transmission Operators.
R2.
Each Transmission Operator shall acquire sufficient reactive resources within its area to
protect the voltage levels under normal and Contingency conditions. This includes the
Transmission Operator’s share of the reactive requirements of interconnecting transmission
circuits.
R3.
The Transmission Operator shall specify criteria that exempts generators from compliance
with the requirements defined in Requirement 4, and Requirement 6.1.
R3.1.
Each Transmission Operator shall maintain a list of generators in its area that are
exempt from following a voltage or Reactive Power schedule.
R3.2.
For each generator that is on this exemption list, the Transmission Operator shall
notify the associated Generator Owner.
R4.
Each Transmission Operator shall specify a voltage or Reactive Power schedule 1 at the
interconnection between the generator facility and the Transmission Owner's facilities to be
maintained by each generator. The Transmission Operator shall provide the voltage or
Reactive Power schedule to the associated Generator Operator and direct the Generator
Operator to comply with the schedule in automatic voltage control mode (AVR in service
and controlling voltage).
R5.
Each Purchasing-Selling Entity shall arrange for (self-provide or purchase) reactive
resources to satisfy its reactive requirements identified by its Transmission Service
Provider.
R6.
The Transmission Operator shall know the status of all transmission Reactive Power
resources, including the status of voltage regulators and power system stabilizers.
R6.1.
R7.
1
Six months after BOT adoption.TBD
When notified of the loss of an automatic voltage regulator control, the
Transmission Operator shall direct the Generator Operator to maintain or change
either its voltage schedule or its Reactive Power schedule.
The Transmission Operator shall be able to operate or direct the operation of devices
necessary to regulate transmission voltage and reactive flow.
The voltage schedule is a target voltage to be maintained within a tolerance band during a specified period.
Board of Trustees Adoption: August 2, 2006TBD
Effective Date: Six months after BOT adoption.TBD
Page 1 of 3
Standard VAR-001-X1 — Voltage and Reactive Control
R8.
Each Transmission Operator shall operate or direct the operation of capacitive and
inductive reactive resources within its area – including reactive generation scheduling;
transmission line, Generator Interconnection Facility, and reactive resource switching; and,
if necessary, load shedding – to maintain system and Interconnection voltages within
established limits.
R9.
Each Transmission Operator shall maintain reactive resources to support its voltage under
first Contingency conditions.
R9.1.
Each Transmission Operator shall disperse and locate the reactive resources so
that the resources can be applied effectively and quickly when Contingencies
occur.
R10. Each Transmission Operator shall correct IROL or SOL violations resulting from reactive
resource deficiencies (IROL violations must be corrected within 30 minutes) and complete
the required IROL or SOL violation reporting.
R11. After consultation with the Generator Owner regarding necessary step-up transformer tap
changes, the Transmission Operator shall provide documentation to the Generator Owner
specifying the required tap changes, a timeframe for making the changes, and technical
justification for these changes.
R12. The Transmission Operator shall direct corrective action, including load reduction,
necessary to prevent voltage collapse when reactive resources are insufficient.
C.
Measures
M1. The Transmission Operator shall have evidence it provided a voltage or Reactive Power
schedule as specified in Requirement 4 to each Generator Operator it requires to follow such a
schedule.
M2. The Transmission Operator shall have evidence to show that, for each generating unit in its
area that is exempt from following a voltage or Reactive Power schedule, the associated
Generator Owner was notified of this exemption in accordance with Requirement 3.2.
M3. The Transmission Operator shall have evidence to show that it issued directives as specified in
Requirement 6.1 when notified by a Generator Operator of the loss of an automatic voltage
regulator control.
M4. The Transmission Operator shall have evidence that it provided documentation to the
Generator Owner when a change was needed to a generating unit’s step-up transformer tap in
accordance with Requirement 11.
D.
Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Transmission Operator shall retain evidence for Measures 1 through 4 for 12 months.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
Board of Trustees Adoption: August 2, 2006TBD
Effective Date: Six months after BOT adoption.TBD
Page 2 of 3
Standard VAR-001-X1 — Voltage and Reactive Control
The Transmission Operator shall demonstrate compliance through self-certification or
audit (periodic, as part of targeted monitoring or initiated by complaint or event), as
determined by the Compliance Monitor.
2.
Levels of Non-Compliance
2.1. Level 1:
No evidence that exempt Generator Owners were notified of their
exemption as specified under R3.2
2.2. Level 2:
There shall be a level two non-compliance if either of the following
conditions exists:
2.2.1
No evidence to show that directives were issued in accordance with R6.1.
2.2.2
No evidence that documentation was provided to Generator Owner when a
change was needed to a generating unit’s step-up transformer tap in accordance
with R11.
2.3. Level 3:
There shall be a level three non-compliance if either of the following
conditions exists:
2.3.1
Voltage or Reactive Power schedules were provided for some but not all
generating units as required in R4.
2.4. Level 4:
No evidence voltage or Reactive Power schedules were provided to
Generator Operators as required in R4.
D.
Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
August 2, 2006
BOT Adoption
Revised
1
July 3, 2007
Added “Generator Owners” and “Generator
Operators” to Applicability section.
Errata
1
August 23, 2007
Removed “Generator Owners” and
“Generator Operators” to Applicability
section.
Errata
X
TBD
Modified R8 to include Generator
Interconnection Facility
Addition
Board of Trustees Adoption: August 2, 2006TBD
Effective Date: Six months after BOT adoption.TBD
Page 3 of 3
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
A. Introduction
1.
Title:
Generator Operation for Maintaining Network Voltage Schedules
2.
Number:
VAR-002-X1.1a
3.
Purpose:
To ensure generators provide reactive and voltage control necessary to ensure
voltage levels, reactive flows, and reactive resources are maintained within applicable Facility
Ratings to protect equipment and the reliable operation of the Interconnection.
4.
Applicability
4.1. Generator Operator.
4.2. Generator Owner.
5.
Effective Date:
May 13, 2009TBD
B. Requirements
R1.
The Generator Operator shall operate each generator connected to the interconnected
transmission system in the automatic voltage control mode (automatic voltage regulator in
service and controlling voltage) unless the Generator Operator has notified the Transmission
Operator.
R2.
Unless exempted by the Transmission Operator, each Generator Operator shall maintain the
generator voltage or Reactive Power output (within applicable Facility Ratings 1) as directed by
the Transmission Operator.
R3.
R4.
R2.1.
When a generator’s automatic voltage regulator is out of service, the Generator
Operator shall use an alternative method to control the generator voltage and reactive
output to meet the voltage or Reactive Power schedule directed by the Transmission
Operator.
R2.2.
When directed to modify voltage, the Generator Operator shall comply or provide an
explanation of why the schedule cannot be met.
Each Generator Operator shall notify its associated Transmission Operator as soon as practical,
but within 30 minutes of any of the following:
R3.1.
A status or capability change on any generator Reactive Power resource, including the
status of each automatic voltage regulator and power system stabilizer and the
expected duration of the change in status or capability.
R3.2.
A status or capability change on any other Reactive Power resources under the
Generator Operator’s control, including the Generator Interconnection Facility, and
the expected duration of the change in status or capability.
The Generator Owner shall provide the following to its associated Transmission Operator and
Transmission Planner within 30 calendar days of a request.
R4.1.
For generator step-up transformers and auxiliary transformers with primary voltages
equal to or greater than the generator terminal voltage:
R4.1.1. Tap settings.
R4.1.2. Available fixed tap ranges.
1
When a Generator is operating in manual control, reactive power capability may change based on stability
considerations and this will lead to a change in the associated Facility Ratings.
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 1 of 6
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
R4.1.3. Impedance data.
R4.1.4. The +/- voltage range with step-change in % for load-tap changing
transformers.
R5.
After consultation with the Transmission Operator regarding necessary step-up transformer tap
changes, the Generator Owner shall ensure that transformer tap positions are changed
according to the specifications provided by the Transmission Operator, unless such action
would violate safety, an equipment rating, a regulatory requirement, or a statutory requirement.
R5.1.
If the Generator Operator can’t comply with the Transmission Operator’s
specifications, the Generator Operator shall notify the Transmission Operator and
shall provide the technical justification.
C. Measures
M1. The Generator Operator shall have evidence to show that it notified its associated Transmission
Operator any time it failed to operate a generator in the automatic voltage control mode as
specified in Requirement 1.
M2. The Generator Operator shall have evidence to show that it controlled its generator voltage and
reactive output to meet the voltage or Reactive Power schedule provided by its associated
Transmission Operator as specified in Requirement 2.
M3. The Generator Operator shall have evidence to show that it responded to the Transmission
Operator’s directives as identified in Requirement 2.1 and Requirement 2.2.
M4. The Generator Operator shall have evidence it notified its associated Transmission Operator
within 30 minutes of any of the changes identified in Requirement 3.
M5. The Generator Owner shall have evidence it provided its associated Transmission Operator and
Transmission Planner with information on its step-up transformers and auxiliary transformers
as required in Requirements 4.1.1 through 4.1.4
M6. The Generator Owner shall have evidence that its step-up transformer taps were modified per
the Transmission Operator’s documentation as identified in Requirement 5.
M7. The Generator Operator shall have evidence that it notified its associated Transmission
Operator when it couldn’t comply with the Transmission Operator’s step-up transformer tap
specifications as identified in Requirement 5.1.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The Generator Operator shall maintain evidence needed for Measure 1 through Measure
5 and Measure 7 for the current and previous calendar years.
The Generator Owner shall keep its latest version of documentation on its step-up and
auxiliary transformers. (Measure 6)
The Compliance Monitor shall retain any audit data for three years.
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 2 of 6
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
1.4. Additional Compliance Information
The Generator Owner and Generator Operator shall each demonstrate compliance
through self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Levels of Non-Compliance for Generator Operator
2.1. Level 1: There shall be a Level 1 non-compliance if any of the following conditions
exist:
2.1.1
One incident of failing to notify the Transmission Operator as identified in ,
R3.1, R3.2 or R5.1.
2.1.2
One incident of failing to maintain a voltage or reactive power schedule (R2).
2.2. Level 2: There shall be a Level 2 non-compliance if any of the following conditions
exist:
2.2.1
More than one but less than five incidents of failing to notify the Transmission as
identified in R1, R3.1,R3.2 or R5.1.
2.2.2
More than one but less than five incidents of failing to maintain a voltage or
reactive power schedule (R2).
2.3. Level 3: There shall be a Level 3 non-compliance if any of the following conditions
exist:
2.3.1
More than five but less than ten incidents of failing to notify the Transmission
Operator as identified in R1, R3.1, R3.2 or R5.1.
2.3.2
More than five but less than ten incidents of failing to maintain a voltage or
reactive power schedule (R2).
2.4. Level 4: There shall be a Level 4 non-compliance if any of the following conditions
exist:
3.
2.4.1
Failed to comply with the Transmission Operator’s directives as identified in R2.
2.4.2
Ten or more incidents of failing to notify the Transmission Operator as identified
in R1, R3.1, R3.2 or R5.1.
2.4.3
Ten or more incidents of failing to maintain a voltage or reactive power schedule
(R2).
Levels of Non-Compliance for Generator Owner:
3.1.1
Level One: Not applicable.
3.1.2
Level Two: Documentation of generator step-up transformers and auxiliary
transformers with primary voltages equal to or greater than the generator terminal
voltage was missing two of the data types identified in R4.1.1 through R4.1.4.
3.1.3
Level Three: No documentation of generator step-up transformers and auxiliary
transformers with primary voltages equal to or greater than the generator terminal
voltage
3.1.4
Level Four: Did not ensure generating unit step-up transformer settings were
changed in compliance with the specifications provided by the Transmission
Operator as identified in R5.
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 3 of 6
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
E. Regional Differences
None identified.
F. Associated Documents
1.
Appendix 1 – Interpretation of Requirements R1 and R2 (August 1, 2007).
Version History
Version
Date
Action
Change Tracking
1
May 15, 2006
Added “(R2)” to the end of levels on noncompliance 2.1.2, 2.2.2, 2.3.2, and 2.4.3.
July 5, 2006
1a
December 19,
2007
Added Appendix 1 – Interpretation of R1
and R2 approved by BOT on August 1,
2007
Revised
1a
January 16,
2007
In Section A.2., Added “a” to end of
standard number.
Section F: added “1.”; and added date.
Errata
1.1a
October 29,
2008
BOT adopted errata changes; updated
version number to “1.1a”
Errata
1.1a
May 13, 2009
FERC Approved – Updated Effective Date
and Footer
Revised
X
TBD
Modified R3.2 to include the Generator
Interconnection Facility
Addition
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 4 of 6
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
Appendix 1
Interpretation of Requirements R1 and R2
Request:
Requirement R1 of Standard VAR-002-1 states that Generation Operators shall operate each generator
connected to the interconnected transmission system in the automatic voltage control mode (automatic
voltage regulator in service and controlling voltage) unless the Generator Operator has notified the
Transmission Operator.
Requirement R2 goes on to state that each Generation Operator shall maintain the generator voltage or
Reactive Power output as directed by the Transmission Operator.
The two underlined phrases are the reasons for this interpretation request.
Most generation excitation controls include a device known as the Automatic Voltage Regulator, or AVR.
This is the device which is referred to by the R1 requirement above. Most AVR’s have the option of
being set in various operating modes, such as constant voltage, constant power factor, and constant Mvar.
In the course of helping members of the WECC insure that they are in full compliance with NERC
Reliability Standards, I have discovered both Transmission Operators and Generation Operators who have
interpreted this standard to mean that AVR operation in the constant power factor or constant Mvar
modes complies with the R1 and R2 requirements cited above. Their rational is as follows:
The AVR is clearly in service because it is operating in one of its operating modes
The AVR is clearly controlling voltage because to maintain constant PF or constant Mvar, it
controls the generator terminal voltage
R2 clearly gives the Transmission Operator the option of directing the Generation Operator to
maintain a constant reactive power output rather than a constant voltage.
Other parties have interpreted this standard to require operation in the constant voltage mode only. Their
rational stems from the belief that the purpose of the VAR-002-1 standard is to insure the automatic
delivery of additional reactive to the system whenever a voltage decline begins to occur.
The material impact of misinterpretation of these standards is twofold.
First, misinterpretation may result in reduced reactive response during system disturbances,
which in turn may contribute to voltage collapse.
Second, misinterpretation may result in substantial financial penalties imposed on generation
operators and transmission operators who believe that they are in full compliance with the
standard.
In accordance with the NERC Reliability Standards Development Procedure, I am requesting that a
formal interpretation of the VAR-002-1 standard be provided. Two specific questions need to be
answered.
First, does AVR operation in the constant PF or constant Mvar modes comply with R1?
Second, does R2 give the Transmission Operator the option of directing the Generation Owner to
operate the AVR in the constant Pf or constant Mvar modes rather than the constant voltage
mode?
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 5 of 6
Standard VAR-002-1X.1a — Generator Operation for Maintaining Network Voltage
Schedules
Interpretation:
1. First, does AVR operation in the constant PF or constant Mvar modes comply with R1?
Interpretation: No, only operation in constant voltage mode meets this requirement. This
answer is predicated on the assumption that the generator has the physical equipment that
will allow such operation and that the Transmission Operator has not directed the generator
to run in a mode other than constant voltage.
2. Second, does R2 give the Transmission Operator the option of directing the Generation
Owner (sic) to operate the AVR in the constant Pf or constant Mvar modes rather than the
constant voltage mode?
Interpretation: Yes, if the Transmission Operator specifically directs a Generator Operator to
operate the AVR in a mode other than constant voltage mode, then that directed mode of AVR
operation is allowed.
Board of Trustees Adoption: October 29, 2008TBD
Effective Date: May 13, 2009TBD
Page 6 of 6
Final Report from the Ad Hoc Group
for Generator Requirements at the
Transmission Interface
November 16, 2009
Table of Contents
Executive Summary .........................................................................................................................3
Conclusions................................................................................................................................. 3
Recommendations ............................................................................................................................5
Historical Perspective ................................................................................................................. 6
Team Objective........................................................................................................................... 7
Team Composition...................................................................................................................... 8
Problem Statement ...................................................................................................................... 8
Problem Statement:..................................................................................................................... 9
Issues List.................................................................................................................................. 10
Appendix 1 — Review of NERC Reliability Standards Requirements.........................................21
Appendix 2 — Proposed Revisions to the Statement of Compliance Registry Criteria................97
Appendix 3 — Proposed Standards Authorization Request and Redline Standard Revisions....108
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
2
Executive Summary
Conclusions
1. Generator Interconnection Facilities operating at a voltage of 100 kV or greater or those
deemed critical to the Bulk Electric System by the Regional Entity makes the Generator
Interconnection Facility part of the Bulk Electric System for purposes of applying Generator
Owner and Generator Operator requirements but not for applying Transmission Owner or
Transmission Operator requirements.
2. The Generator Owner or Generator Operator that owns and/or operates a Generator
Interconnection Facility, that is, a sole-use facility that interconnects the generator to the grid,
should not be registered as a Transmission Owner or Transmission Operator by virtue of
owning or operating its Generator Interconnection Facility.
3. A Generator Interconnection Facility is considered as though part of the generating facility
specifically for purposes of applying Reliability Standards to a Generator Owner or
Generator Operator.
4. Changes to NERC Reliability Standards are needed to ensure complete reliability coverage of
the Generator Interconnection Facility.
a. 32 NERC Reliability Standard requirements contain language regarding generators or
generating facilities for which greater clarity regarding its Generator Interconnection
Facilities would ensure that no reliability gap exists.
b. 12 requirements in FAC-003-1 – Transmission Vegetation Management should have
their applicability expanded to include Generator Owners.
c. 2 NERC Reliability Standards should have their applicability expanded to include
Generator Operators to address general reliability gaps not attributable to the Generator
Interconnection Facility.
d. 8 new Reliability Standard requirements should be added to ensure the responsibilities
for owning and operating the Generator Interconnection Facility are clear, and to
address certain requirements that should apply to all generators regardless of
interconnection configuration.
5. If a generator is connected to multiple transmission facilities that are subject to network
power flows (that is, power flow on these multiple transmission facilities includes power not
solely associated with the generator output, requirements for station service, auxiliary load,
or cogeneration load), then those transmission facilities are integrated transmission facilities
and should be subjected to the applicable Transmission Owner and Transmission Operator
Standard Requirements 1.
6. After review of the existing Transmission Owner requirements that are not currently
applicable to Generator Owners, only FAC-003-1 should have its applicability expanded to
include Generator Owners as a result of the Generator Interconnection Facility, if the length
1
A double-circuit line behind the point of interconnection, for example, that is carrying power solely associated with
the generation output, requirements for station service, auxiliary load, or cogeneration load, would not be considered
an integrated transmission facility by comparison.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
3
of the Generator Interconnection Facility exceeds two spans (generally, more than one-half
mile) from the generator property line.
7. After review of the existing Transmission Operator requirements that are not currently
applicable to Generator Operators, no existing Transmission Operator requirements should
apply to Generator Operators as a result of the Generator Interconnection Facility.
8. New NERC Glossary definitions are needed for Generator Interconnection Facility and
Generator Interconnection Operational Interface, as well as modifications to the terms
Vegetation Inspection, Right-of-Way, Generator Owner, Generator Operator, and
Transmission.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
4
Recommendations
1. Submit Standards Authorization Requests (SARs) requesting expeditious action to add or
modify the definitions in NERC’s Glossary for Generator Interconnection Facility and
Generator Interconnection Operational Interface, as well as modifications to the terms
Vegetation Inspection, Right-of-Way, Generator Owner, Generator Operator, and
Transmission.
2. Submit SARs requesting expeditious action to modify existing standard requirements to add
specificity for Generator Interconnection Facility where appropriate, to add Generator
Operator applicability where needed, to add requirements to capture responsibilities for
owning and operating the Generator Interconnection Facility, and to add requirements where
necessary that should be applicable to Generator Operators regardless of the interconnection
configuration.
3. Modify the applicability of FAC-003-1 to apply to Generator Owners when their Generator
Interconnection Facility operates at 200 kV or above and exceeds two spans from the
generator property line, or otherwise is deemed to be critical to the Bulk Electric System.
4. Modify the NERC Rules of Procedure, NERC Compliance Registry Criteria, and other
documents as necessary to reflect that a Generator Owner should not be registered as a
Transmission Owner and a Generator Operator should not be registered as a Transmission
Operator on the basis of the Generator Interconnection Facility.
5. NERC and the Regional Entities should refrain from further registering Generator Owners
and Generator Operators as Transmission Owners and Transmission Operators generically by
virtue of the Generator Interconnection Facility.
6. Based on the conclusions and recommendations offered in this report, NERC and the
Regional Entities should carefully develop and implement a plan to address de-registering
those Generator Owners and Generator Operators that have previously been registered as a
Transmission Owner and Transmission Operator by virtue of the Generator Interconnection
Facility.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
5
Discussion
Historical Perspective
On January 14, 2008, the NERC Board of Trustees Compliance Committee rendered a decision
upholding the Western Electricity Coordinating Council’s (WECC’s) determination to register
the New Harquahala Generating Company (“Harquahala”) as a Transmission Owner and
Transmission Operator. This determination is based on Harquahala’s 26-mile 500 kV
interconnection facilities that connect the plant with the Hassayampa transmission substation. In
its determination, NERC concluded that:
Harquahala met its glossary definition of “Transmission Owner” and “Transmission
Operator”;
Harquahala’s interconnection facilities are integrated transmission elements as described
in NERC’s Compliance Registry because they interconnect the generating facility to the
transmission grid; and,
Harquahala as a generating facility and the transmission station to which it interconnects
are material to the Bulk Power System.
As a result, NERC found that Harquahala must be registered as a Transmission Owner and
Transmission Operator in order to provide for proper coordination between Harquahala and Salt
River Project, owner and operator of the Hassayampa substation, and for proper operation and
maintenance of the interconnection facilities. NERC stated that a reliability gap exists because
several high risk Reliability Standards do not otherwise apply to Harquahala under its other
registration functions including those for vegetation management; taking corrective action if a
protective relay failure reduces system reliability; coordinating protection systems; analyzing
protection system misoperations and developing a corrective action plan to avoid future
misoperations; developing procedures for monitoring voltage levels and reactive flow; and
exercising the responsibility and clear decision-making authority to take actions needed to ensure
the reliability of its area and to take action to alleviate operating emergencies. NERC stated,
“from a reliability perspective and from the standpoint of section 215 of the FPA, this
transmission line is integrated with other elements of the [Bulk Power System] requiring
coordination of operation with those other elements.” NERC also noted that Harquahala’s
registration status is based on ownership of its generation facilities, while its Transmission
Owner and Transmission Operator status are based on ownership and operation of the
transmission facilities.
In its appeal to FERC, Harquahala argued that its interconnection facilities were not integrated
transmission elements; that its facilities will not have a material impact on the Bulk-Power
System; that registration as a Transmission Owner and Transmission Operator is unwarranted
because there is no reliability gap; and that its registration as such would result in inconsistent
registrations in WECC and other regions. Harquahala notably did not contest that its
interconnection facilities were part of the Bulk Power System.
FERC denied Harquahala’s appeal on the material impact of the assets to the reliability of the
Bulk Power System, but declined to address issues regarding the NERC Compliance Registry
Criteria and the definition of “integrated transmission element.” FERC noted that “if Harquahala
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
6
is only registered as a Generator Owner and Generator Operator, and not a Transmission Owner
and Transmission Operator, it will not be required to have its staff trained and NERC-certified to
operate these facilities in an emergency or to coordinate protection for its transmission line and
switchyard with other transmission operators and the Regional Entity.” Further, FERC noted
that if adequate reliability requirements were not provided on Harquahala’s tie-line, there is a
reliability risk affecting a significant portion of the Bulk Power System in WECC confirming
that a reliability gap exists. Significantly, FERC indicated that its finding in this case is casespecific and not one that all tie-line owners and operators should now be registered as
Transmission Owners and Transmission Operators. Because Harquahala cannot physically
comply with all transmission owner and transmission operator requirements in NERC standards,
FERC directed NERC and Harquahala to negotiate those that will be applicable to them. This
activity was completed in July, 2008.
The impact of the Harquahala registration decision manifested itself in a concern by some
Generator Owners and Generator Operators regarding the criteria (or the lack thereof) that would
be used to consistently determine whether other Generator Owners and Generator Operators
would be also subject to registration as a Transmission Owner and Transmission Operator. In
addition to the Harquahala case, there have been a small number of similar appeals to registration
decisions on this issue that resulted in the registration of Generator Owners and or Generator
Operators as Transmission Owners and or Operators. It is not clearly known the number of
Generator Owners and Generator Operators also registered as Transmission Owners and
Transmission Operators by virtue of its interconnection facilities that have chosen not to appeal.
In response to this growing concern, NERC undertook a survey in the Fall, 2008 to identify the
specific nature of the concerns, to review and highlight those Transmission Owner and
Transmission Operator requirements that should be considered for generic applicability to
Generator Owners and Generator Operators by virtue of their interconnection facilities, and to
collect ideas for how the issue could be resolved. There were wide-ranging viewpoints to the
topic from the over 100 respondents but there was no support for merely assigning all
Transmission Owner and Transmission Operator Requirements to the Generator Owner and
Generator Operator on the basis of their interconnection facilities. One consistent suggestion
was to assemble a group of industry representatives to analyze and make recommendations for
resolving the issue, thereby establishing general criteria for determining whether Generator
Owners and Generator Operators should be registered for Transmission Owner and Transmission
Operator requirements in NERC’s Reliability Standards.
Accordingly, in February, 2009, NERC announced the formation of the Ad Hoc Group for
Generator Requirements at the Transmission Interface.
Team Objective
“Evaluate existing NERC Reliability Standard requirements and develop a recommendation and
possible Standards Authorization Request to address gaps in reliability for interconnection
facilities of the Generator Owner and expectations for the Generator Operator in operating those
facilities. Propose strategies to address or resolve other related issues as appropriate.”
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Team Composition
The team was selected to provide a cross-section of participants across different geographic
regions and industry segments, specifically linked with various NERC technical groups, and
representative of both the operating and planning perspectives. The size of the team was
intentionally managed to foster and efficient and effective disposition of the team’s obligations.
The team consisted of the following members:
Scott Helyer, Chair
Steven Cobb
Keith Daniel
Jeffrey Gillen
Anthony Jankowski
Gregory Mason
Eric Mortenson
Timothy Ponseti
Kent Saathoff
Gerry Adamski
Tenaska, Inc.
Salt River Project
Georgia Transmission Corporation
American Transmission Corporation
We Energies
Dynegy
Exelon Energy Delivery
Tennessee Valley Authority
Electric Reliability Council of Texas, Inc.
NERC Staff Coordinator
Problem Statement
The team devoted effort at the outset to clearly define and understand the problem that the team
was organized to address. In this deliberation and determination, the team developed the
following problem statement, assumptions, and process description that it used to guide its
activities thereafter as presented in Exhibit 1:
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Exhibit 1
Problem Statement:
Certain equipment owned and/or operated by generators may be defined as part of the Bulk
Electric System. As such, the team needs to determine which owner and operating requirements
are needed for reliability purposes for these facilities and then identify the functional entity 2
accountable for compliance to those requirements.
Assumptions:
1. There are pieces of equipment at 100 kV and above currently owned and operated by
generators that may fall under the definition of Bulk Electric System and therefore are
under the purview of the NERC Reliability Standards.
2. For pieces of equipment identified in assumption No. 1 above, at least one functional
entity must be identified to be responsible for each standard requirement applicable to
these facilities at an ownership and operating level, understanding that multiple
ownership and operating arrangements exist. 3
3. Separate the ownership expectations from the operating expectations in the discussion.
4. Current standard requirements assigned to Generator Owners and Generator Operators
are appropriate.
Process to Address Identified Problem:
1. Review the list of standard requirements applicable to Transmission Owners and/or
Transmission Operators that are not currently applicable to Generator Owners and/or
Generator Operators.
2. Determine which of the Transmission Owner standard requirements not assigned to
Generator Owners should always be, never be, or could possibly be assigned to address
potential reliability gaps based on the equipment owned by the Generator Owner.
3. Determine which of the Transmission Operator standard requirements not assigned to
Generator Operators should always be, never be, or could possibly be assigned to address
potential reliability gaps based on the equipment operated by the Generator Operator.
4. Determine if these requirements are already covered by other existing reliability standard
requirements.
5. If not, determine a strategy for identifying the functional entity that should be assigned
the responsibility for these requirements, not necessarily limited to the current list of
functional entities.
2
The use of the term “functional entity” is not intended to limit team consideration to those functional entities
currently utilized in NERC’s Reliability Standards. If in its deliberation, the team identifies a new functional entity
that should be defined; the team can make such a proposal.
3
The goal is to assign responsibility for these requirements to a single functional entity but recognize that clear
delineation of these responsibilities must be identified when multiple entity arrangements apply.
Generator Requirements at the Transmission Interface Final Report
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6. Perform sensitivity analyses using the list of “parking lot” questions/issues to determine
further activities for the team.
7. Finalize recommendations within a final report that includes potential SARs.
Issues List
The industry survey that NERC conducted in late 2008 led to the identification of 17 issues for
team consideration that are presented below. This list of issues was included in the original
proposal that recommended the formation of the team. The team to varying degrees addressed
these issues as discussed below, and in several cases, captured the response to related issues in
one response. The discussion that follows includes the summary of the team’s deliberation and
the rationale for the conclusion the team reached on each issue, and any recommendations that
resulted from those discussions. During the course of these discussions, the team carefully
separated the impact of the generating unit itself from the impact from the generator’s
interconnection facilities. Stated more specifically, the team considered whether there were
certain of NERC’s existing Transmission Owner and Transmission Operator requirements that
currently do not apply but should apply to the Generator Owner and or Generator Operator by
virtue of the interconnection facilities that connect the generating unit to the grid and the various
configurations therein. However, the team did not consider the potential loss of energy produced
by the generator as a sufficient basis to apply Transmission Owner and or Transmission Operator
standards to the generator. In circumstances where improvement to a requirement is needed and
is applicable because of the generating plant itself and not because of the interconnection facility,
the team identified the needed change and noted it as a generic generator issue. In its resolution
of these issues, the team considered the owner requirements apart from the operator
requirements.
1. Identify what is needed to ensure the reliable supply of real and reactive power to the
grid; and determine the goal of the Generator Owner and Generator Operator
Requirements (bulk electric system reliability vs. interconnection facility reliability).
The team concluded that to the extent a generator’s interconnection facilities met the current
NERC Glossary Definition as Bulk Electric System, that is, facilities operating above 100 kV
or those deemed critical to the reliability of the Bulk Electric System as defined by the
Regional Entity, then those facilities are part of the generating facility and are appropriately
classified as part of the Bulk Electric System for purposes of applying Generator Owner and
Generator Operator requirements, but not for applying Transmission Owner or Transmission
Operator Requirements. In this construct, the Generator Owner and Generator Operator has
responsibility for the Generator Interconnection Facility (as defined herein) and the
Transmission Owner and Transmission Operator has responsibility for the transmission
facilities that connect to the Generator Interconnection Facility, and importantly, has
operating responsibility for the Generator Interconnection Operational Interface (as defined
herein). This approach ensures that no reliability gap exists for the Generator
Interconnection Facility. Please continue with the response to Issue 2 for further discussion
on the role of Generation Owners and Operators.
2. Affect of interconnection configuration on standard requirements and applicability
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10
The team discussed the varying system configurations that could exist at the generating
facility end of the interconnection facility and on the transmission grid side of the
interconnection facility. The team quickly concluded that the core issue was the applicability
of requirements for sole-use interconnection facilities, that is, those facilities whose singular
purpose is to connect the generating facility (inclusive of associated station service load,
auxiliary load, or cogeneration load) to the interconnected grid. In this context, facilities
such as double circuit lines or the various substation configurations that may exist at the
generator facility are included as part of the Generator Interconnection Facility provided their
purpose is limited to transmitting power from the plant, provision of station service, auxiliary
load requirements, or provision of cogeneration load requirements. For other configurations
in which the interconnection facility is used by other parties to tie to other substations or to
customer loads or where a generator is connected to multiple transmission facilities of other
parties, these facilities are considered integrated for the purposes of standard applicability
and the full spectrum of Transmission Owner and Transmission Operator requirements
would apply as appropriate.
The team also concluded that an outage of the Generator Interconnection Facility that results
in an outage of an integrated transmission line (such as exists in a three-terminal or T-tap
configuration) does not provide a sufficient basis for making the Generator Interconnection
Facility subject to Transmission Owner and Transmission Operator standard requirements.
In fact, the NERC Statement of Compliance Registry Criteria (Revision 5.0) includes an
exclusion from registration for “radial transmission facilities serving only load with one
transmission source” which would include similar configurations such as T-taps or threeterminal lines. In the case of radial facilities serving only load, the obligations for PRC-type
requirements, for example, are included by virtue of the registration as another functional
entity besides a Transmission Owner (for instance, as a Distribution Provider assuming the
entity meets the Registry criteria for such inclusion). Similarly, Generator Owners that meet
the Registry criteria will necessarily be responsible for relevant PRC-type requirements.
Considering sole-use interconnection facilities, the team determined that greater specificity in
the current standards is necessary to clearly define and identify Generator Interconnection
Facility “as a recognized term and to apply the term where appropriate in certain of the
requirements to ensure a clear understanding of expectations. The team therefore proposes
below to add a definition of Generator Interconnection Facility to the NERC Glossary and
several changes to requirements to include this term. Similarly, the team recommends a
proposed new definition and application of the term “Generator Interconnection Operational
Interface” in the NERC Glossary and in several standard requirements.
The team also considered various scenarios pertaining to the relationship of the Generator
Owner to the Transmission Owner regarding the interconnection facility equipment. If a
Generator Owner owns the physical equipment that resides in the Transmission Owner
substation at the Generator Interconnection Operational Interface, the team believed that the
Generator Owner would not have the independent ability to access or affect the equipment
without interfacing with the Transmission Owner; rather, the Generator Owner would
necessarily have to coordinate with the Transmission Owner to gain access to the station and
work under escort to perform activities on the equipment it owned. As a result, the team
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11
believes that in this scenario, the Generator Owner should not be required to be registered as
a Transmission Owner directly.
When viewed at the operational level, considerable discussion ensued regarding the
relationship between the Generator Operator and Transmission Operator for operation of the
Generator Interconnection Facility, that is, the sole-use interconnection facility. While
generally accepted that the Generator Owner owns the Generator Interconnection Facility,
the team recognized that the Generator Operator over the facility must use reasonable means
to coordinate the operation of that facility in order to preserve the reliability of the grid to
which it is interconnected, when the facility is energized and synchronized to the grid or
when the interconnection facility is about to be de-energized from or re-energized to the
transmission system 4. The Generator Operator must understand the potential impact to the
interconnected transmission system for the actions that they perform on the Generator
Interconnection Facility and must therefore be provided focused training for the reliable
execution of those responsibilities. Importantly, however, the Transmission Operator to
whom the Generator Interconnection Facility interconnects has the decision-making
operational authority over the Generator Interconnection Operational Interface.
In response to comments received during the public posting of the initial report, the team also
discussed the treatment of the Generator Interconnection Facility of small generators not
registered as a Generator Owner and Generator Operator. The team concluded that to the
extent that a Regional Entity believes that a small generator and/or its Generator
Interconnection Facility is material to the reliability of the Bulk Electric System, it has the
right to make such a demonstration and propose registration of the entity as a Generator
Owner and Generator Operator. In fact, this report’s conclusion that the Generator
Interconnection Facility is considered part of the generating facility may benefit 1) the
Regional Entity in making a demonstration of materiality as well as 2) the generator if such a
demonstration is made. In this regard, the Regional Entity will be able to make its
demonstration of materiality on the basis of the generating facility (which includes the
Generator Interconnection Facility) instead of having to make separate materiality
demonstrations for both the generating unit(s) and the Generator Interconnection Facility.
Therefore, if a small generating facility and its Generator Interconnection Facility are
demonstrated to be material to the reliability of the Bulk Electric System, they would then be
registered as a Generator Owner and Generator Operator and subject to Generator Owner and
Generator Operator standards but not subject to Transmission Owner and Transmission
Operator standard requirements.
The approach posited in this report acknowledges that the Generator Interconnection Facility,
as defined herein, functions for a singular and well-defined purpose, to transmit power to and
from the generating plant and for purposes of station service, auxiliary load requirements, or
for cogeneration load. As such, these facilities are different in usage than transmission
facilities that comprise the interconnected grid. The team carefully reviewed all
Transmission Owner requirements for application to the Generator Interconnection Facility
and recommend adjustments to several requirements to clarify expectations for the Generator
4
Except for situations involving imminent equipment damage or personnel safety for which the Generator Operator
may be required to act without coordination with the Transmission Operator.
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Owners. Thus, the team believes that these changes ensure consistent expectations at an
ownership level. At an operating level, a number of Transmission Operator requirements
exist for operating an interconnected transmission grid and a number of closely related
Generator Operator requirements are applicable to the Generator Interconnection Facility
based on the recommendations contained in this report. Additionally, in a similar fashion to
the exclusion provided to radial transmission serving only load in the existing NERC
definition of Bulk Electric System and that pertaining to of the inclusion of distribution
provider facilities involved in underfrequency load shedding, the Generator Interconnection
Facility is proposed to be addressed by NERC standards based on their use Accordingly, the
approach proposed implements a strategy to ensure no gaps in reliability coverage exist
relative to the Generator Interconnection Facility. By virtue of the recommendation to
process the standard changes using the NERC Reliability Standard Development Procedure,
the specific approach contained herein will be further vetted with ample opportunity for
stakeholder review, input, modification as necessary, and approval before implementation.
3. Review GO/GOP and TO/TOP Requirements to identify reliability gaps
The group spent a significant amount of time reviewing first the Transmission Owner
requirements, and then the Transmission Operator requirements currently approved for
enforcement but not currently applicable to the Generator Owners or Generator Operators.
This bifurcated review carefully considered whether a specific requirement should be made
applicable to the Generator Owner or Generator Operator solely on the basis of the Generator
Interconnection Facility, and not on the basis of the generator itself. In conducting this
review, it became apparent to the team that certain requirements presented a potential
reliability gap because the Generator Operator was not listed as an applicable entity based on
the generator itself (but not because of its interconnection facility). The team also carefully
reviewed the Generator Owner and Generator Operator requirements and concluded that the
responsibilities for owning and operating the Generator Interconnection Facility could best
be clarified by making certain Generator Owner and Generator Operator requirement
language more specific to include the term “Generator Interconnection Facility”. The redline
changes to the NERC Standards that highlight these changes are included in Appendix 1.
The following description summarizes the proposed standard requirement changes.
The team identified 32 requirements in which the Generator Interconnection Facility
is specifically added to the requirement.
The team identified 12 requirements in FAC-003-1 – Transmission Vegetation
Management that need to include the Generator Owner as an applicable entity based
on the conclusions discussed later in the report.
The team noted 2 requirements whose applicability should be expanded to address
generic issues associated with the generating facility and not necessarily with respect
to the Generator Interconnection Facility.
The team identified the need to add 8 new standard requirements to fully clarify the
expectations with regard to the Generator Interconnection Facility, heretofore implied
in the Standards, or to address certain requirements that should apply to all generators
regardless of interconnection configuration as follows.
Generator Requirements at the Transmission Interface Final Report
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1.
The Generator Operator who has responsibility for monitoring the status of a
special protection system or remedial action scheme at the generating facility
for the benefit of Bulk Electric System reliability should notify the
Transmission Operator when a change in status or capability occurs.
2.
Each Generator Operator shall provide its operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable
and reliable operation of the Generation Facility and the Generation
Interconnection Facility, and to implement directives of the Transmission
Operator and Balancing Authority.
3.
Each Generator Operator shall implement an initial and continuing training
program for all personnel responsible for operating the Generator
Interconnection Facility to ensure the ability to operate the equipment in a
reliable manner.
4.
The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it
interconnects to preserve Interconnection reliability.
5.
The Transmission Operator has decision-making authority for the Generator
Interconnection Operational Interface.
6.
The Generator Operator shall notify the Transmission Operator of a change in
status of the Generation Interconnection Facility.
7.
The Generator Operator shall operate the Generation Interconnection Facility
within Facility Ratings.
8.
The Generator Operator shall disconnect the Generation Interconnection
Facility immediately in coordination with the Transmission Operator when time
permits or as soon as practical thereafter if an overload or other abnormal
condition threatens equipment or personnel safety.
Regarding item new requirement No. 3, the team does not intend that this requirement results
in a need for NERC-certified transmission or generator operators at the generating plant by
virtue of the Generator Interconnection Facility. Rather, the training program must contain
the necessary elements for the Generator Operator tasked with operating the Generator
Interconnection Facility to understand fully the impacts of their operation on the Bulk
Electric System, such as equipment involved, including relaying, the coordination aspects
with the Transmission Operator to which it is connected, and the protocols for and impacts of
operating facilities associated with the Generator Interconnection Facility, including the
Generator Interconnection Operational Interface. The objective of this training is to ensure
that the Generator Operator is completely aware of its obligations to the Transmission
Operators and has the skills and training to execute these obligations in the best interest of
reliability.
In completing the review of standard requirements and the determination therein of needed
changes, the team concluded that there was no basis for assigning existing Transmission
Owner and Transmission Operator standard requirements to the Generator Owner and
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November 16, 2009
14
Generator Operator, respectively, solely on the basis of the Generator Interconnection
Facility, with one exception. The team believes that Standard FAC-003 (Vegetation
Management) should apply to Generator Owners of a Generator Interconnection Facility
whose facilities operate at 200 kV and above or are otherwise deemed critical to the Bulk
Electric System and whose Generation Interconnection Facility exceeds two spans (generally
one-half mile from the generator property line). In reaching this conclusion, the team
considered other options that included inclusion of Generator Owners as applicable entities to
FAC-003 based on a test for criticality, or to include Generator Owners as applicable entities
in the existing version of FAC-003 without modification to the applicability criteria. The
team, supported by a majority of industry commenters indicated the two-span test presented a
simple and objective method to determine responsibilities for Generator Owners.
Additionally, the “200 kV and above, or otherwise deemed critical to the Bulk Electric
System” threshold is consistent with the current applicability of FAC-003 to Transmission
Owners. The rationale for the selection of the two-span criteria is that this distance is in the
generator operator’s line-of-sight and as such could be visually monitored for vegetation
conditions on a routine basis, and beyond which distance a vegetation management program
would be necessary for the Right-of-Way.
In addition regarding the applicability of FAC-003, the group agreed that all units designated
as a blackstart resource that are material to and designated as part of the Transmission
Operator’s system restoration plan, irrespective of voltage level, are deemed to be critical for
purposes of FAC-003 application to the Generator Interconnection Facility, subject to the
two-span criterion. To be material, a blackstart unit is defined as a unit that is part of a
system restoration plan’s facilities that are used to initiate system restoration and establish
the basic minimum power system following a blackout.
4. Defining functional lines of demarcation between the Generator Owner and the
Transmission Owner
The team agrees that the Generator Owner owns the Generator Interconnection Facility and
the Transmission Owner owns the facilities of the interconnection grid to which the
Generator Interconnection Facility connects. Also agreed is that clear operating
responsibility must exist for these facilities. In order to clearly articulate the point at which
the change of operation occurs between the Generator Operator and Transmission Operator,
the team proposes to add a new definition to the NERC Glossary for Generator
Interconnection Operational Interface. The new definition is: location at which operating
responsibility for the Generator Interconnection Facility changes from the Transmission
Operator and the Generator Operator.
5. Impact of operational control or ownership of equipment in the transmission substation
containing the generator interconnection facilities
This issue is addressed in the Issue 2.
6. Effect of FERC-filed Interconnection Agreements and other agreements between
GO/GOP and the TO/TOP
Depending on the vintage, FERC-filed Interconnection Agreements outline to varying
degrees the operating and ownership relationship between the Transmission Provider and the
Generator Requirements at the Transmission Interface Final Report
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15
Interconnection Customer (e.g. Generating Facility). However, the Interconnection
Agreements address the expectations for entities under its jurisdiction with respect to
different sections of the Federal Power Act than Section 215 that addresses reliability and
defines a broader applicability. Therefore, there is an inconsistency in the scope of the
entities for which Interconnection Agreements are required and those under Section 215 of
the Federal Power Act for reliability purposes. Additionally, the functional entity names in
NERC Reliability Standards do not match those terms in the Interconnection Agreements.
For these reasons, the effect of Interconnection Agreements on NERC’s Standards is
debatable.
In addition, NERC’s Reliability Standards must contain the requirements necessary to ensure
an adequate level of reliability for the Bulk Electric System. It is not appropriate for NERC
to rely on other agreements as the primary vehicle to define reliability obligations. Thus,
while the Interconnection Agreements may define greater specificity as to how certain
reliability-related activities are expected to be conducted, NERC Reliability Standards must
contain what is required from a performance outcome. The team has evaluated the current
set of requirements to validate that the necessary requirements are in place; and to the extent
improvements or additions are needed, identified those modifications or new obligations.
7. Bifurcated review of GO Requirements and GOP Requirements
The team agreed that it is necessary and appropriate to consider the Generator Owner
Requirements distinct from the Generator Operator requirements as discussed in Issue 3.
8. Review NERC Glossary definitions for Transmission, Generator Owner, Generator
Operator, Transmission Owner, and Transmission Operator
The team reviewed the definitions listed in the NERC Glossary of Terms and considered
additional terms as they impacted the intent and meaning of certain requirements currently
applicable to the Transmission Operator or Transmission Owner. The team believed that
modifications to some and additions of several new terms were needed to add greater clarity
to the applicability of requirements pertaining to the generator interconnection facilities.
Transmission — the team agreed with the existing definition but determined it
necessary to add a sentence to specify that the Generator Interconnection Facility is
not part of the definition. The proposed definition with the modification italicized is
as follows:
Transmission
An interconnected group of lines and associated equipment for the movement or
transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems.
Generator Interconnection Facility is not included in this definition.
Generator Owner — the team agreed with the existing definition but determined it
necessary to add a phrase that specifies the inclusion of the generator’s
interconnection facilities. The proposed definition is as follows:
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Generator Owner
Entity that owns and maintains generating units, including its Generator
Interconnection Facility
Generator Operator — the team agreed with the existing definition but determined it
necessary to add a sentence to indicate that operational coordination was necessary
with the Transmission Operator for the Generator Interconnection Facility. With the
modification italicized, the proposed definition is:
Generator Operator
The entity that operates generating unit(s) and the Generator Interconnection Facility
and performs the functions of supplying energy and Interconnected Operations
Services. The Generator Operator also operates the Generator Interconnection
Facility and is responsible for coordinating with the Transmission Operator when the
facility is energized or about to be energized to/de-energized from the transmission
system.
Transmission Owner — no changes are necessary
Transmission Operator — no changes are necessary
The team also considered the terms, Transmission Line, Element, Facility, Interconnection,
and System and do not recommend changes to these terms. Further, the team recommends
improvements to the terms, Right-of-Way and Vegetation Inspection to encompass the
Generator Interconnection Facility, and proposes two new terms, Generator Interconnection
Facility and Generator Interconnection Operational Interface as follows:
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The Transmission Owner
owner of the electric lines may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
Vegetation Inspection
The systematic examination of a transmission corridor Transmission Line or Generator
Interconnection Facility Right-of-Way to document vegetation conditions.
Generator Interconnection Facility (NEW)
Sole-use facility for the purpose of connecting the generating unit(s) to the transmission
grid. In this regard, the sole-use facility only transmits power associated with the
interconnecting generator, whether delivered to the grid or delivered to the generator for
station service or auxiliary load, or delivered to meet cogeneration load requirements.
Generator Interconnection Operational Interface (NEW)
Location at which operating responsibility for the Generator Interconnection Facility
changes between the Transmission Operator and the Generator Operator.
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These terms will be incorporated as recommended changes to existing standard
requirements through the standards authorization requests contained in Appendix C.
9. NERC Compliance Registry Guidance
The team identified that companion changes to NERC’s Statement of Compliance Registry
are required to incorporate the changes to the definitions for Generator Owner and Generator
Operator proposed by the group. As outlined in Exhibit B, specific modifications are
required in Section II of the document with respect to the definitions of Generator Owner and
Generator Operator as proposed in this report. Additional changes are necessary in Section
III.c.4 and III.d.2 to provide the proposed definition of Generator Interconnection Facility
and to specify that the Generator Interconnection Facility is considered part of the generating
facility and not the integrated transmission system for purposes of applying the registry
criteria.
In addition, the group believes it appropriate to include definitive statements such that it is
clear that a Generator Owner or Generator Operator should not be registered as a
Transmission Owner or Transmission Operator, respectively, solely resulting from the
Generator Interconnection Facility as defined herein. These modifications will ensure
consistency in application of the NERC Reliability Standards to those Generator Owners
identified through implementation of the NERC Compliance Registry processes.
In addition, NERC and the Regional Entities should carefully develop and implement a plan
to address de-registering those Generator Owners and Generator Operators that have
previously been registered as a Transmission Owner and Transmission Operator by virtue of
the Generator Interconnection Facility. The team recognizes that Regional Entities have
discretion to determine critical facilities within its footprint in individual case-by-case
assessments.
10. Material Impact Test for Generator Interconnection Facilities
The group concluded that only one existing Reliability Standard that is applicable to
Transmission Owners, FAC-003-1, should have its applicability expanded to Generator
Owners because of their Generator Interconnection Facility. Although the two-span test
noted in Proposal 2 was selected as the most appropriate approach, the following list contains
a summary of the three proposals that were considered:
Proposal 1 — A straightforward criterion suggested is to apply FAC-003-1 for the Generator
Interconnection Facility per the current standard’s applicability.
Proposal 2 — A second proposal is based on Proposal 1 but provides an exclusion for short
distance Rights-of-Way that are generally within line of sight from the generating plant. This
proposal calls for applying FAC-003-1 for the Generator Interconnection Facility operating
above 200 kV that extend beyond two tower spans (i.e. ½ mile) from the generating plant
property line.
Proposal 3 — A third proposal applies FAC-003-1 to the Generator Interconnection Facility
that operates at 200 kV or above and that is deemed critical to the Bulk Electric System. In
Generator Requirements at the Transmission Interface Final Report
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18
this regard, the criticality test as discussed by the team would be the following: the Generator
Owner would coordinate with the Transmission Planner to perform an impact based test
utilizing similar criteria to that outlined in TPL-003-0 Table 1 Category C that assesses
system performance under scenarios involving more than one contingency event.
Particularly, the team agreed that the engineering analysis would be based on the system
performance expectations of a single-line-to-ground fault on the interconnection facility with
delayed clearing or a stuck breaker. Under these conditions, the criticality test would be met
if the system response to these contingency events resulted in cascading outages, system
instability, or operating outside applicable ratings, with loss of firm load or the curtailment of
third-party firm transfers that is not associated with the loss of the generating plant output
directly connected to the Generator Interconnection Facility against which the originating
contingency was applied.
The team ultimately relied on additional input received from industry stakeholders during the
comment opportunity to guide its conclusion in this area. Based on the simplicity and
objectiveness of approach, a large number of commenters indicated a preference for Proposal
2. While the criticality test was supported by some, most expressed concern regarding the
resource commitment for analysis and the subjectivity of the approach.
11. Functionality test — Does the facility function as part of the generator function or the
transmission function
Because the generator owns the Generator Interconnection Facility, the team decided that a
Generator Interconnection Facility is considered part of the generator facility. For clarity, a
number of standard requirement modifications or additions are recommended to ensure that
the Generator Interconnection Facility is appropriately considered and that clear
responsibility for ownership and operation are established by those identified as having these
obligations.
12. Approach for multi-unit plants interconnected through a single transmission line
The team considered this issue and supported its earlier determination that a sole-use
interconnection facility should not in and of itself require a Generator Owner and Generator
Operator to be registered as a Transmission Owner and Transmission Operator.
13. Generic application of requirements versus a case-by-case determination
The team determined that through addition or modification of certain standard requirements,
there is no reliability gap by virtue of the Generator Interconnection Facility with one
exception: FAC-003-1 pertaining to transmission vegetation management. The team
determined that FAC-003-1 standard should apply to Generator Owners for facilities
operating above 200 kV or otherwise deemed critical to the Bulk Electric System if the
Generation Interconnection Facility exceeds two-spans, generally one-half mile, from the
generator property line. Otherwise, the standards as modified provide the ability to
generically apply the standard requirements to all Generator Owners and Generator
Operators without introducing or perpetuating any perceived reliability gaps.
14. Affect on the applicability if generators provide ancillary services (reactive control,
regulation, reserves, etc.)
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
19
This issue is addressed previously and is at the discretion of Regional Entities in application
of the definition of Bulk Electric System.
15. Consideration of generators that are included in:
–
–
–
–
–
–
special protection scheme or remedial action scheme
coordinated underfrequency program
coordinated undervoltage program
blackstart
SOL or IROL limits
Provision of firm energy
This issue is addressed previously and is at the discretion of Regional Entities in application of
the definition of Bulk Electric System.
16. Need for additional maintenance-based generator owner requirements on
interconnection facilities when generators already are financially incented to remain
available
The team concluded that to the extent a generator’s interconnection facilities meet the current
NERC Glossary Definition as Bulk Electric System, that is, facilities operating above 100 kV
or those deemed critical to the reliability of the Bulk Electric System as defined by the
Regional Entity, then those facilities are appropriately classified as part of the Bulk Electric
System for purposes of applying Generator Owner and Generator Operator requirements but
not for applying Transmission Owner or Transmission Operator requirements For
interconnection facilities classified as such, an entity must be designated to be responsible for
relevant ownership and operation obligations. These obligations manifest themselves as
requirements in the Reliability Standards to ensure an adequate level of reliability is
maintained on the Bulk Electric System. Therefore, specification of ownership and
operational requirements for a Generator Interconnection Facility is necessary to ensure the
expected performance is achieved consistent with the reliability objectives being sought.
While the statement is undoubtedly true that generators, including its interconnection
facilities, are motivated to remain available to be capable of delivering energy (and capacity)
to the grid, these self-directed motivations do not adequately assure that the obligations for
reliability of the Bulk Electric System will be supported under all circumstances. Developing
NERC Reliability Standard requirements to address these expectations further incent the
Generator Owner and Generator Operator to execute their responsibilities consistent with
NERC’s reliability obligations.
17. Develop new transmission functional category know as Generator-Tie
The team considered whether the addition of a new Generator-Tie functional category would
add the clarity needed to ensure that standard requirements applicable to generator
interconnection facilities would result in no reliability gaps. Upon reflection, the team
determined that it could achieve the intended purpose through the inclusion the modified and
new definitions proposed, and their application to the existing standard requirements. This
would result in significantly less effort to implement in the standards, greater industry
acceptance, and thus a shorter timeframe to implement on the whole.
Generator Requirements at the Transmission Interface Final Report
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Appendix 1 — Review of NERC Reliability Standards
Requirements
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Standard
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BAL-005-0.1b
R1.
All generation, transmission, and load operating within an
Interconnection must be included within the metered boundaries
of a Balancing Authority Area.
GOP
BAL-005-0.1b
R1.1.
Each Generator Operator with generation facilities, including its
Generator Interconnection Facility, operating in an
Interconnection shall ensure that those generation facilities are
included within the metered boundaries of a Balancing
Authority Area.
GOP
BAL-005-0.1b
R1.2.
Each Transmission Operator with transmission facilities
operating in an Interconnection shall ensure that those
transmission facilities are included within the metered
boundaries of a Balancing Authority Area.
CIP-001-1
R1.
Each Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, and Load-Serving
Entity shall have procedures for the recognition of and for
making their operating personnel aware of sabotage events on
its facilities and multi site sabotage affecting larger portions of
the Interconnection.
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CIP-001-1
R2.
Each Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, and Load-Serving
Entity shall have procedures for the communication of
information concerning sabotage events to appropriate parties in
the Interconnection.
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CIP-001-1
R3.
Each Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, and Load-Serving
Entity shall provide its operating personnel with sabotage
response guidelines, including personnel to contact, for
reporting disturbances due to sabotage events.
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CIP-001-1
R4.
Each Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, and Load-Serving
Entity shall establish communications contacts, as applicable,
with local Federal Bureau of Investigation (FBI) or Royal
Canadian Mounted Police (RCMP) officials and develop
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reporting procedures as appropriate to their circumstances.
CIP-002-1
R1.
Critical Asset Identification Method — The Responsible Entity
shall identify and document a risk-based assessment
methodology to use to identify its Critical Assets.
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CIP-002-1
R1.1.
The Responsible Entity shall maintain documentation describing
its risk-based assessment methodology that includes procedures
and evaluation criteria.
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CIP-002-1
R1.2.
The risk-based assessment shall consider the following assets:
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CIP-002-1
R1.2.1.
Control centers and backup control centers performing the
functions of the entities listed in the Applicability section of this
standard.
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CIP-002-1
R1.2.2.
Transmission substations that support the reliable operation of
the Bulk Electric System.
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CIP-002-1
R1.2.3.
Generation resources, including the Generator Interconnection
Facility, that support the reliable operation of the Bulk Electric
System.
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CIP-002-1
R1.2.4.
Systems and facilities critical to system restoration, including
blackstart generators and their attendant Generator
Interconnection Facility, and substations in the electrical path of
transmission lines used for initial system restoration.
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CIP-002-1
R1.2.5.
Systems and facilities critical to automatic load shedding under
a common control system capable of shedding 300 MW or
more.
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CIP-002-1
R1.2.6.
Special Protection Systems that support the reliable operation of
the Bulk Electric System.
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CIP-002-1
R1.2.7.
Any additional assets that support the reliable operation of the
Bulk Electric System that the Responsible Entity deems
appropriate to include in its assessment.
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CIP-002-1
R2.
Critical Asset Identification — The Responsible Entity shall
develop a list of its identified Critical Assets determined through
an annual application of the risk-based assessment methodology
required in R1. The Responsible Entity shall review this list at
least annually, and update it as necessary.
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CIP-002-1
R3.
Critical Cyber Asset Identification — Using the list of Critical
Assets developed pursuant to Requirement R2, the Responsible
Entity shall develop a list of associated Critical Cyber Assets
essential to the operation of the Critical Asset. Examples at
control centers and backup control centers include systems and
facilities at master and remote sites that provide monitoring and
control, automatic generation control, real-time power system
modeling, and real-time inter-utility data exchange. The
Responsible Entity shall review this list at least annually, and
update it as necessary. For the purpose of Standard CIP-002,
Critical Cyber Assets are further qualified to be those having at
least one of the following characteristics:
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CIP-002-1
R3.1.
The Cyber Asset uses a routable protocol to communicate
outside the Electronic Security Perimeter; or,
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CIP-002-1
R3.2.
The Cyber Asset uses a routable protocol within a control
center; or,
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CIP-002-1
R3.3.
The Cyber Asset is dial-up accessible.
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CIP-002-1
R4.
Annual Approval — A senior manager or delegate(s) shall
approve annually the list of Critical Assets and the list of
Critical Cyber Assets. Based on Requirements R1, R2, and R3
the Responsible Entity may determine that it has no Critical
Assets or Critical Cyber Assets. The Responsible Entity shall
keep a signed and dated record of the senior manager or
delegate(s)’s approval of the list of Critical Assets and the list of
Critical Cyber Assets (even if such lists are null.)
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CIP–003–1
R1.
Cyber Security Policy — The Responsible Entity shall
document and implement a cyber security policy that represents
management’s commitment and ability to secure its Critical
Cyber Assets. The Responsible Entity shall, at minimum, ensure
the following:
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CIP–003–1
R1.1.
The cyber security policy addresses the requirements in
Standards CIP-002 through CIP-009, including provision for
emergency situations.
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CIP–003–1
R1.2.
The cyber security policy is readily available to all personnel
who have access to, or are responsible for, Critical Cyber
Assets.
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CIP–003–1
R1.3.
Annual review and approval of the cyber security policy by the
senior manager assigned pursuant to R2.
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CIP–003–1
R2.
Leadership — The Responsible Entity shall assign a senior
manager with overall responsibility for leading and managing
the entity’s implementation of, and adherence to, Standards
CIP-002 through CIP-009
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CIP–003–1
R2.1.
The senior manager shall be identified by name, title, business
phone, business address, and date of designation.
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CIP–003–1
R2.2.
Changes to the senior manager must be documented within
thirty calendar days of the effective date.
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CIP–003–1
R2.3.
The senior manager or delegate(s), shall authorize and document
any exception from the requirements of the cyber security
policy.
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CIP–003–1
R3.
Exceptions — Instances where the Responsible Entity cannot
conform to its cyber security policy must be documented as
exceptions and authorized by the senior manager or delegate(s).
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CIP–003–1
R3.1.
Exceptions to the Responsible Entity’s cyber security policy
must be documented within thirty days of being approved by the
senior manager or delegate(s).
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CIP–003–1
R3.2.
Documented exceptions to the cyber security policy must
include an explanation as to why the exception is necessary and
any compensating measures, or a statement accepting risk.
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CIP–003–1
R3.3.
Authorized exceptions to the cyber security policy must be
reviewed and approved annually by the senior manager or
delegate(s) to ensure the exceptions are still required and valid.
Such review and approval shall be documented.
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CIP–003–1
R4.
Information Protection — The Responsible Entity shall
implement and document a program to identify, classify, and
protect information associated with Critical Cyber Assets.
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CIP–003–1
R4.1.
The Critical Cyber Asset information to be protected shall
include, at a minimum and regardless of media type, operational
procedures, lists as required in Standard CIP-002, network
topology or similar diagrams, floor plans of computing centers
that contain Critical Cyber Assets, equipment layouts of Critical
Cyber Assets, disaster recovery plans, incident response plans,
and security configuration information.
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CIP–003–1
R4.2.
The Responsible Entity shall classify information to be
protected under this program based on the sensitivity of the
Critical Cyber Asset information.
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CIP–003–1
R4.3.
The Responsible Entity shall, at least annually, assess adherence
to its Critical Cyber Asset information protection program,
document the assessment results, and implement an action plan
to remediate deficiencies identified during the assessment.
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CIP–003–1
R5.
Access Control — The Responsible Entity shall document and
implement a program for managing access to protected Critical
Cyber Asset information.
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CIP–003–1
R5.1.
The Responsible Entity shall maintain a list of designated
personnel who are responsible for authorizing logical or
physical access to protected information.
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CIP–003–1
R5.1.1.
Personnel shall be identified by name, title, business phone and
the information for which they are responsible for authorizing
access.
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CIP–003–1
R5.1.2.
The list of personnel responsible for authorizing access to
protected information shall be verified at least annually.
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CIP–003–1
R5.2.
The Responsible Entity shall review at least annually the access
privileges to protected information to confirm that access
privileges are correct and that they correspond with the
Responsible Entity’s needs and appropriate personnel roles and
responsibilities.
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CIP–003–1
R5.3.
The Responsible Entity shall assess and document at least
annually the processes for controlling access privileges to
protected information.
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CIP–003–1
R6.
Change Control and Configuration Management — The
Responsible Entity shall establish and document a process of
change control and configuration management for adding,
modifying, replacing, or removing Critical Cyber Asset
hardware or software, and implement supporting configuration
management activities to identify, control and document all
entity or vendor related changes to hardware and software
components of Critical Cyber Assets pursuant to the change
control process.
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CIP-004-1
R1.
Awareness — The Responsible Entity shall establish, maintain,
and document a security awareness program to ensure personnel
having authorized cyber or authorized unescorted physical
access receive on-going reinforcement in sound security
practices. The program shall include security awareness
reinforcement on at least a quarterly basis using mechanisms
such as: Direct communications (e.g., emails, memos, computer
based training, etc.); Indirect communications (e.g., posters,
intranet, brochures, etc.); Management support and
reinforcement (e.g., presentations, meetings, etc.).
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CIP-004-1
R2.
Training — The Responsible Entity shall establish, maintain,
and document an annual cyber security training program for
personnel having authorized cyber or authorized unescorted
physical access to Critical Cyber Assets, and review the
program annually and update as necessary.
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CIP-004-1
R2.1.
This program will ensure that all personnel having such access
to Critical Cyber Assets, including contractors and service
vendors, are trained within ninety calendar days of such
authorization.
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CIP-004-1
R2.2.
Training shall cover the policies, access controls, and
procedures as developed for the Critical Cyber Assets covered
by CIP-004, and include, at a minimum, the following required
items appropriate to personnel roles and responsibilities:
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CIP-004-1
R2.2.1.
The proper use of Critical Cyber Assets;
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CIP-004-1
R2.2.2.
Physical and electronic access controls to Critical Cyber Assets;
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CIP-004-1
R2.2.3.
The proper handling of Critical Cyber Asset information; and,
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CIP-004-1
R2.2.4.
Action plans and procedures to recover or re-establish Critical
Cyber Assets and access thereto following a Cyber Security
Incident.
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CIP-004-1
R2.3.
The Responsible Entity shall maintain documentation that
training is conducted at least annually, including the date the
training was completed and attendance records.
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CIP-004-1
R3.
Personnel Risk Assessment —The Responsible Entity shall have
a documented personnel risk assessment program, in accordance
with federal, state, provincial, and local laws, and subject to
existing collective bargaining unit agreements, for personnel
having authorized cyber or authorized unescorted physical
access. A personnel risk assessment shall be conducted pursuant
to that program within thirty days of such personnel being
granted such access. Such program shall at a minimum include:
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CIP-004-1
R3.1.
The Responsible Entity shall ensure that each assessment
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conducted include, at least, identity verification (e.g., Social
Security Number verification in the U.S.) and seven year
criminal check. The Responsible Entity may conduct more
detailed reviews, as permitted by law and subject to existing
collective bargaining unit agreements, depending upon the
criticality of the position.
CIP-004-1
R3.2.
The Responsible Entity shall update each personnel risk
assessment at least every seven years after the initial personnel
risk assessment or for cause.
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CIP-004-1
R3.3.
The Responsible Entity shall document the results of personnel
risk assessments of its personnel having authorized cyber or
authorized unescorted physical access to Critical Cyber Assets,
and that personnel risk assessments of contractor and service
vendor personnel with such access are conducted pursuant to
Standard CIP-004.
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CIP-004-1
R4.
Access — The Responsible Entity shall maintain list(s) of
personnel with authorized cyber or authorized unescorted
physical access to Critical Cyber Assets, including their specific
electronic and physical access rights to Critical Cyber Assets.
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CIP-004-1
R4.1.
The Responsible Entity shall review the list(s) of its personnel
who have such access to Critical Cyber Assets quarterly, and
update the list(s) within seven calendar days of any change of
personnel with such access to Critical Cyber Assets, or any
change in the access rights of such personnel. The Responsible
Entity shall ensure access list(s) for contractors and service
vendors are properly maintained.
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CIP-004-1
R4.2.
The Responsible Entity shall revoke such access to Critical
Cyber Assets within 24 hours for personnel terminated for cause
and within seven calendar days for personnel who no longer
require such access to Critical Cyber Assets.
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CIP-005-1
R1.
Electronic Security Perimeter — The Responsible Entity shall
ensure that every Critical Cyber Asset resides within an
Electronic Security Perimeter. The Responsible Entity shall
identify and document the Electronic Security Perimeter(s) and
all access points to the perimeter(s).
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CIP-005-1
R1.1.
Access points to the Electronic Security Perimeter(s) shall
include any externally connected communication end point (for
example, dial-up modems) terminating at any device within the
Electronic Security Perimeter(s).
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CIP-005-1
R1.2.
For a dial-up accessible Critical Cyber Asset that uses a nonroutable protocol, the Responsible Entity shall define an
Electronic Security Perimeter for that single access point at the
dial-up device.
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CIP-005-1
R1.3.
Communication links connecting discrete Electronic Security
Perimeters shall not be considered part of the Electronic
Security Perimeter. However, end points of these
communication links within the Electronic Security Perimeter(s)
shall be considered access points to the Electronic Security
Perimeter(s).
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CIP-005-1
R1.4.
Any non-critical Cyber Asset within a defined Electronic
Security Perimeter shall be identified and protected pursuant to
the requirements of Standard CIP-005.
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CIP-005-1
R1.5.
Cyber Assets used in the access control and monitoring of the
Electronic Security Perimeter(s) shall be afforded the protective
measures as a specified in Standard CIP-003, Standard CIP-004
Requirement R3, Standard CIP-005 Requirements R2 and R3,
Standard CIP-006 Requirements R2 and R3, Standard CIP-007,
Requirements R1 and R3 through R9, Standard CIP-008, and
Standard CIP-009.
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CIP-005-1
R1.6.
The Responsible Entity shall maintain documentation of
Electronic Security Perimeter(s), all interconnected Critical and
non-critical Cyber Assets within the Electronic Security
Perimeter(s), all electronic access points to the Electronic
Security Perimeter(s) and the Cyber Assets deployed for the
access control and monitoring of these access points.
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CIP-005-1
R2.
Electronic Access Controls — The Responsible Entity shall
implement and document the organizational processes and
technical and procedural mechanisms for control of electronic
access at all electronic access points to the Electronic Security
Perimeter(s).
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CIP-005-1
R2.1.
These processes and mechanisms shall use an access control
model that denies access by default, such that explicit access
permissions must be specified.
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CIP-005-1
R2.2.
At all access points to the Electronic Security Perimeter(s), the
Responsible Entity shall enable only ports and services required
for operations and for monitoring Cyber Assets within the
Electronic Security Perimeter, and shall document, individually
or by specified grouping, the configuration of those ports and
services.
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CIP-005-1
R2.3.
The Responsible Entity shall maintain a procedure for securing
dial-up access to the Electronic Security Perimeter(s).
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CIP-005-1
R2.4.
Where external interactive access into the Electronic Security
Perimeter has been enabled, the Responsible Entity shall
implement strong procedural or technical controls at the access
points to ensure authenticity of the accessing party, where
technically feasible.
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CIP-005-1
R2.5.
The required documentation shall, at least, identify and
describe:
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CIP-005-1
R2.5.1.
The processes for access request and authorization.
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CIP-005-1
R2.5.2.
The authentication methods.
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CIP-005-1
R2.5.3.
The review process for authorization rights, in accordance with
Standard CIP-004 Requirement R4.
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CIP-005-1
R2.5.4.
The controls used to secure dial-up accessible connections.
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CIP-005-1
R2.6.
Appropriate Use Banner — Where technically feasible,
electronic access control devices shall display an appropriate
use banner on the user screen upon all interactive access
attempts. The Responsible Entity shall maintain a document
identifying the content of the banner.
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CIP-005-1
R3.
Monitoring Electronic Access — The Responsible Entity shall
implement and document an electronic or manual process(es)
for monitoring and logging access at access points to the
Electronic Security Perimeter(s) twenty-four hours a day, seven
days a week.
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CIP-005-1
R3.1.
For dial-up accessible Critical Cyber Assets that use nonroutable protocols, the Responsible Entity shall implement and
document monitoring process(es) at each access point to the
dial-up device, where technically feasible.
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CIP-005-1
R3.2.
Where technically feasible, the security monitoring process(es)
shall detect and alert for attempts at or actual unauthorized
accesses. These alerts shall provide for appropriate notification
to designated response personnel. Where alerting is not
technically feasible, the Responsible Entity shall review or
otherwise assess access logs for attempts at or actual
unauthorized accesses at least every ninety calendar days.
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CIP-005-1
R4.
Cyber Vulnerability Assessment — The Responsible Entity
shall perform a cyber vulnerability assessment of the electronic
access points to the Electronic Security Perimeter(s) at least
annually. The vulnerability assessment shall include, at a
minimum, the following:
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CIP-005-1
R4.1.
A document identifying the vulnerability assessment process;
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CIP-005-1
R4.2.
A review to verify that only ports and services required for
operations at these access points are enabled;
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CIP-005-1
R4.3.
The discovery of all access points to the Electronic Security
Perimeter;
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CIP-005-1
R4.4.
A review of controls for default accounts, passwords, and
network management community strings; and,
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CIP-005-1
R4.5.
Documentation of the results of the assessment, the action plan
to remediate or mitigate vulnerabilities identified in the
assessment, and the execution status of that action plan.
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CIP-005-1
R5.
Documentation Review and Maintenance — The Responsible
Entity shall review, update, and maintain all documentation to
support compliance with the requirements of Standard CIP-005.
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CIP-005-1
R5.1.
The Responsible Entity shall ensure that all documentation
required by Standard CIP-005 reflect current configurations and
processes and shall review the documents and procedures
referenced in Standard CIP-005 at least annually.
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CIP-005-1
R5.2.
The Responsible Entity shall update the documentation to
reflect the modification of the network or controls within ninety
calendar days of the change.
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CIP-005-1
R5.3.
The Responsible Entity shall retain electronic access logs for at
least ninety calendar days. Logs related to reportable incidents
shall be kept in accordance with the requirements of Standard
CIP-008.
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CIP-006-1
R1.
Physical Security Plan — The Responsible Entity shall create
and maintain a physical security plan, approved by a senior
manager or delegate(s) that shall address, at a minimum, the
following:
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CIP-006-1
R1.1.
Processes to ensure and document that all Cyber Assets within
an Electronic Security Perimeter also reside within an identified
Physical Security Perimeter. Where a completely enclosed
(“six-wall”) border cannot be established, the Responsible
Entity shall deploy and document alternative measures to
control physical access to the Critical Cyber Assets.
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CIP-006-1
R1.2.
Processes to identify all access points through each Physical
Security Perimeter and measures to control entry at those access
points.
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CIP-006-1
R1.3.
Processes, tools, and procedures to monitor physical access to
the perimeter(s).
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CIP-006-1
R1.4.
Procedures for the appropriate use of physical access controls as
described in Requirement R3 including visitor pass
management, response to loss, and prohibition of inappropriate
use of physical access controls.
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CIP-006-1
R1.5.
Procedures for reviewing access authorization requests and
revocation of access authorization, in accordance with CIP-004
Requirement R4.
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CIP-006-1
R1.6.
Procedures for escorted access within the physical security
perimeter of personnel not authorized for unescorted access.
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CIP-006-1
R1.7.
Process for updating the physical security plan within ninety
calendar days of any physical security system redesign or
reconfiguration, including, but not limited to, addition or
removal of access points through the physical security
perimeter, physical access controls, monitoring controls, or
logging controls.
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CIP-006-1
R1.8.
Cyber Assets used in the access control and monitoring of the
Physical Security Perimeter(s) shall be afforded the protective
measures specified in Standard CIP-003, Standard CIP-004
Requirement R3, Standard CIP-005 Requirements R2 and R3,
Standard CIP-006 Requirement R2 and R3, Standard CIP-007,
Standard CIP-008 and Standard CIP-009.
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CIP-006-1
R1.9.
Process for ensuring that the physical security plan is reviewed
at least annually.
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CIP-006-1
R2.
Physical Access Controls — The Responsible Entity shall
document and implement the operational and procedural
controls to manage physical access at all access points to the
Physical Security Perimeter(s) twenty-four hours a day, seven
days a week. The Responsible Entity shall implement one or
more of the following physical access methods:
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CIP-006-1
R2.1.
Card Key: A means of electronic access where the access rights
of the card holder are predefined in a computer database. Access
rights may differ from one perimeter to another.
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CIP-006-1
R2.2.
Special Locks: These include, but are not limited to, locks with
“restricted key” systems, magnetic locks that can be operated
remotely, and “man-trap” systems.
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CIP-006-1
R2.3.
Security Personnel: Personnel responsible for controlling
physical access who may reside on-site or at a monitoring
station.
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CIP-006-1
R2.4.
Other Authentication Devices: Biometric, keypad, token, or
other equivalent devices that control physical access to the
Critical Cyber Assets.
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CIP-006-1
R3.
Monitoring Physical Access — The Responsible Entity shall
document and implement the technical and procedural controls
for monitoring physical access at all access points to the
Physical Security Perimeter(s) twenty-four hours a day, seven
days a week. Unauthorized access attempts shall be reviewed
immediately and handled in accordance with the procedures
specified in Requirement CIP-008. One or more of the
following monitoring methods shall be used:
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CIP-006-1
R3.1.
Alarm Systems: Systems that alarm to indicate a door, gate or
window has been opened without authorization. These alarms
must provide for immediate notification to personnel
responsible for response.
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CIP-006-1
R3.2.
Human Observation of Access Points: Monitoring of physical
access points by authorized personnel as specified in
Requirement R2.3.
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CIP-006-1
R4.
Logging Physical Access — Logging shall record sufficient
information to uniquely identify individuals and the time of
access twenty-four hours a day, seven days a week. The
Responsible Entity shall implement and document the technical
and procedural mechanisms for logging physical entry at all
access points to the Physical Security Perimeter(s) using one or
more of the following logging methods or their equivalent:
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CIP-006-1
R4.1.
Computerized Logging: Electronic logs produced by the
Responsible Entity’s selected access control and monitoring
method.
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CIP-006-1
R4.2.
Video Recording: Electronic capture of video images of
sufficient quality to determine identity.
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CIP-006-1
R4.3.
Manual Logging: A log book or sign-in sheet, or other record of
physical access maintained by security or other personnel
authorized to control and monitor physical access as specified in
Requirement R2.3.
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CIP-006-1
R5.
Access Log Retention — The Responsible Entity shall retain
physical access logs for at least ninety calendar days. Logs
related to reportable incidents shall be kept in accordance with
the requirements of Standard CIP-008.
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CIP-006-1
R6.
Maintenance and Testing — The Responsible Entity shall
implement a maintenance and testing program to ensure that all
physical security systems under Requirements R2, R3, and R4
function properly. The program must include, at a minimum, the
following:
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CIP-006-1
R6.1.
Testing and maintenance of all physical security mechanisms on
a cycle no longer than three years.
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CIP-006-1
R6.2.
Retention of testing and maintenance records for the cycle
determined by the Responsible Entity in Requirement R6.1.
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CIP-006-1
R6.3.
Retention of outage records regarding access controls, logging,
and monitoring for a minimum of one calendar year.
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CIP-007-1
R1.
Test Procedures — The Responsible Entity shall ensure that
new Cyber Assets and significant changes to existing Cyber
Assets within the Electronic Security Perimeter do not adversely
affect existing cyber security controls. For purposes of Standard
CIP-007, a significant change shall, at a minimum, include
implementation of security patches, cumulative service packs,
vendor releases, and version upgrades of operating systems,
applications, database platforms, or other third-party software or
firmware.
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CIP-007-1
R1.1.
The Responsible Entity shall create, implement, and maintain
cyber security test procedures in a manner that minimizes
adverse effects on the production system or its operation.
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CIP-007-1
R1.2.
The Responsible Entity shall document that testing is performed
in a manner that reflects the production environment.
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CIP-007-1
R1.3.
The Responsible Entity shall document test results.
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CIP-007-1
R2.
Ports and Services — The Responsible Entity shall establish and
document a process to ensure that only those ports and services
required for normal and emergency operations are enabled.
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CIP-007-1
R2.1.
The Responsible Entity shall enable only those ports and
services required for normal and emergency operations.
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CIP-007-1
R2.2.
The Responsible Entity shall disable other ports and services,
including those used for testing purposes, prior to production
use of all Cyber Assets inside the Electronic Security
Perimeter(s).
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CIP-007-1
R2.3.
In the case where unused ports and services cannot be disabled
due to technical limitations, the Responsible Entity shall
document compensating measure(s) applied to mitigate risk
exposure or an acceptance of risk.
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CIP-007-1
R3.
Security Patch Management — The Responsible Entity, either
separately or as a component of the documented configuration
management process specified in CIP-003 Requirement R6,
shall establish and document a security patch management
program for tracking, evaluating, testing, and installing
applicable cyber security software patches for all Cyber Assets
within the Electronic Security Perimeter(s).
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CIP-007-1
R3.1.
The Responsible Entity shall document the assessment of
security patches and security upgrades for applicability within
thirty calendar days of availability of the patches or upgrades.
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CIP-007-1
R3.2.
The Responsible Entity shall document the implementation of
security patches. In any case where the patch is not installed, the
Responsible Entity shall document compensating measure(s)
applied to mitigate risk exposure or an acceptance of risk.
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CIP-007-1
R4.
Malicious Software Prevention — The Responsible Entity shall
use anti-virus software and other malicious software
(“malware”) prevention tools, where technically feasible, to
detect, prevent, deter, and mitigate the introduction, exposure,
and propagation of malware on all Cyber Assets within the
Electronic Security Perimeter(s).
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CIP-007-1
R4.1.
The Responsible Entity shall document and implement antivirus and malware prevention tools. In the case where anti-virus
software and malware prevention tools are not installed, the
Responsible Entity shall document compensating measure(s)
applied to mitigate risk exposure or an acceptance of risk.
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CIP-007-1
R4.2.
The Responsible Entity shall document and implement a process
for the update of anti-virus and malware prevention
“signatures.” The process must address testing and installing the
signatures.
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CIP-007-1
R5.
Account Management — The Responsible Entity shall establish,
implement, and document technical and procedural controls that
enforce access authentication of, and accountability for, all user
activity, and that minimize the risk of unauthorized system
access.
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CIP-007-1
R5.1.
The Responsible Entity shall ensure that individual and shared
system accounts and authorized access permissions are
consistent with the concept of “need to know” with respect to
work functions performed.
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CIP-007-1
R5.1.1.
The Responsible Entity shall ensure that user accounts are
implemented as approved by designated personnel. Refer to
Standard CIP-003 Requirement R5.
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CIP-007-1
R5.1.2.
The Responsible Entity shall establish methods, processes, and
procedures that generate logs of sufficient detail to create
historical audit trails of individual user account access activity
for a minimum of ninety days.
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CIP-007-1
R5.1.3.
The Responsible Entity shall review, at least annually, user
accounts to verify access privileges are in accordance with
Standard CIP-003 Requirement R5 and Standard CIP-004
Requirement R4.
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CIP-007-1
R5.2.
The Responsible Entity shall implement a policy to minimize
and manage the scope and acceptable use of administrator,
shared, and other generic account privileges including factory
default accounts.
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CIP-007-1
R5.2.1.
The policy shall include the removal, disabling, or renaming of
such accounts where possible. For such accounts that must
remain enabled, passwords shall be changed prior to putting any
system into service.
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CIP-007-1
R5.2.2.
The Responsible Entity shall identify those individuals with
access to shared accounts.
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CIP-007-1
R5.2.3.
Where such accounts must be shared, the Responsible Entity
shall have a policy for managing the use of such accounts that
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limits access to only those with authorization, an audit trail of
the account use (automated or manual), and steps for securing
the account in the event of personnel changes (for example,
change in assignment or termination).
CIP-007-1
R5.3.
At a minimum, the Responsible Entity shall require and use
passwords, subject to the following, as technically feasible:
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CIP-007-1
R5.3.1.
Each password shall be a minimum of six characters.
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CIP-007-1
R5.3.2.
Each password shall consist of a combination of alpha, numeric,
and “special” characters.
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CIP-007-1
R5.3.3.
Each password shall be changed at least annually, or more
frequently based on risk.
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CIP-007-1
R6.
Security Status Monitoring — The Responsible Entity shall
ensure that all Cyber Assets within the Electronic Security
Perimeter, as technically feasible, implement automated tools or
organizational process controls to monitor system events that
are related to cyber security.
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CIP-007-1
R6.1.
The Responsible Entity shall implement and document the
organizational processes and technical and procedural
mechanisms for monitoring for security events on all Cyber
Assets within the Electronic Security Perimeter.
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CIP-007-1
R6.2.
The security monitoring controls shall issue automated or
manual alerts for detected Cyber Security Incidents.
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CIP-007-1
R6.3.
The Responsible Entity shall maintain logs of system events
related to cyber security, where technically feasible, to support
incident response as required in Standard CIP-008.
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CIP-007-1
R6.4.
The Responsible Entity shall retain all logs specified in
Requirement R6 for ninety calendar days.
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CIP-007-1
R6.5.
The Responsible Entity shall review logs of system events
related to cyber security and maintain records documenting
review of logs.
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CIP-007-1
R7.
Disposal or Redeployment — The Responsible Entity shall
establish formal methods, processes, and procedures for disposal
or redeployment of Cyber Assets within the Electronic Security
Perimeter(s) as identified and documented in Standard CIP-005.
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CIP-007-1
R7.1.
Prior to the disposal of such assets, the Responsible Entity shall
destroy or erase the data storage media to prevent unauthorized
retrieval of sensitive cyber security or reliability data.
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CIP-007-1
R7.2.
Prior to redeployment of such assets, the Responsible Entity
shall, at a minimum, erase the data storage media to prevent
unauthorized retrieval of sensitive cyber security or reliability
data.
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CIP-007-1
R7.3.
The Responsible Entity shall maintain records that such assets
were disposed of or redeployed in accordance with documented
procedures.
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CIP-007-1
R8.
Cyber Vulnerability Assessment — The Responsible Entity
shall perform a cyber vulnerability assessment of all Cyber
Assets within the Electronic Security Perimeter at least
annually. The vulnerability assessment shall include, at a
minimum, the following:
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CIP-007-1
R8.1.
A document identifying the vulnerability assessment process;
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CIP-007-1
R8.2.
A review to verify that only ports and services required for
operation of the Cyber Assets within the Electronic Security
Perimeter are enabled;
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CIP-007-1
R8.3.
A review of controls for default accounts; and,
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CIP-007-1
R8.4.
Documentation of the results of the assessment, the action plan
to remediate or mitigate vulnerabilities identified in the
assessment, and the execution status of that action plan.
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CIP-007-1
R9.
Documentation Review and Maintenance — The Responsible
Entity shall review and update the documentation specified in
Standard CIP-007 at least annually. Changes resulting from
modifications to the systems or controls shall be documented
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within ninety calendar days of the change.
CIP–008–1
R1.
Cyber Security Incident Response Plan — The Responsible
Entity shall develop and maintain a Cyber Security Incident
response plan. The Cyber Security Incident Response plan shall
address, at a minimum, the following:
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CIP–008–1
R1.1.
Procedures to characterize and classify events as reportable
Cyber Security Incidents.
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CIP–008–1
R1.2.
Response actions, including roles and responsibilities of
incident response teams, incident handling procedures, and
communication plans.
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CIP–008–1
R1.3.
Process for reporting Cyber Security Incidents to the Electricity
Sector Information Sharing and Analysis Center (ES ISAC).
The Responsible Entity must ensure that all reportable Cyber
Security Incidents are reported to the ES ISAC either directly or
through an intermediary.
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CIP–008–1
R1.4.
Process for updating the Cyber Security Incident response plan
within ninety calendar days of any changes.
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CIP–008–1
R1.5.
Process for ensuring that the Cyber Security Incident response
plan is reviewed at least annually.
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CIP–008–1
R1.6.
Process for ensuring the Cyber Security Incident response plan
is tested at least annually. A test of the incident response plan
can range from a paper drill, to a full operational exercise, to the
response to an actual incident.
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CIP–008–1
R2.
Cyber Security Incident Documentation — The Responsible
Entity shall keep relevant documentation related to Cyber
Security Incidents reportable per Requirement R1.1 for three
calendar years.
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CIP–009–1
R1.
Recovery Plans — The Responsible Entity shall create and
annually review recovery plan(s) for Critical Cyber Assets. The
recovery plan(s) shall address at a minimum the following:
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CIP–009–1
R1.1.
Specify the required actions in response to events or conditions
of varying duration and severity that would activate the recovery
plan(s).
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CIP–009–1
R1.2.
Define the roles and responsibilities of responders.
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CIP–009–1
R2.
Exercises — The recovery plan(s) shall be exercised at least
annually. An exercise of the recovery plan(s) can range from a
paper drill, to a full operational exercise, to recovery from an
actual incident.
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CIP–009–1
R3.
Change Control — Recovery plan(s) shall be updated to reflect
any changes or lessons learned as a result of an exercise or the
recovery from an actual incident. Updates shall be
communicated to personnel responsible for the activation and
implementation of the recovery plan(s) within ninety calendar
days of the change.
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CIP–009–1
R4.
Backup and Restore — The recovery plan(s) shall include
processes and procedures for the backup and storage of
information required to successfully restore Critical Cyber
Assets. For example, backups may include spare electronic
components or equipment, written documentation of
configuration settings, tape backup, etc.
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CIP–009–1
R5.
Testing Backup Media — Information essential to recovery that
is stored on backup media shall be tested at least annually to
ensure that the information is available. Testing can be
completed off site.
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COM-001-1
R1.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information:
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COM-001-1.1
R1.1.
Internally.
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COM-001-1.1
R1.2.
Between the Reliability Coordinator and its Transmission
Operators and Balancing Authorities.
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COM-001-1.1
R1.3.
With other Reliability Coordinators, Transmission Operators,
and Balancing Authorities as necessary to maintain reliability.
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COM-001-1.1
R1.4.
Where applicable, these facilities shall be redundant and
diversely routed.
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COM-001-1.1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications.
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COM-001-1.1
R3.
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide a means to coordinate
telecommunications among their respective areas. This
coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas.
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COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use
English as the language for all communications between and
among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations.
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COM-001-1.1
R5.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions
and procedures to enable continued operation of the system
during the loss of telecommunications facilities.
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COM-002-2
R1.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall have communications (voice and data
links) with appropriate Reliability Coordinators, Balancing
Authorities, and Transmission Operators. Such communications
shall be staffed and available for addressing a real-time
emergency condition.
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COM-002-2
R1.1.
Each Balancing Authority and Transmission Operator shall
notify its Reliability Coordinator, and all other potentially
affected Balancing Authorities and Transmission Operators
through predetermined communication paths of any condition
that could threaten the reliability of its area or when firm load
shedding is anticipated.
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COM-002-2
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise,
and definitive manner; shall ensure the recipient of the directive
repeats the information back correctly; and shall acknowledge
the response as correct or repeat the original statement to
resolve any misunderstandings.
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EOP-001-0
R2.
The Transmission Operator shall have an emergency load
reduction plan for all identified IROLs. The plan shall include
the details on how the Transmission Operator will implement
load reduction in sufficient amount and time to mitigate the
IROL violation before system separation or collapse would
occur. The load reduction plan must be capable of being
implemented within 30 minutes.
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EOP-001-0
R3.
Each Transmission Operator and Balancing Authority shall:
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EOP-001-0
R3.1.
Develop, maintain, and implement a set of plans to mitigate
operating emergencies for insufficient generating capacity.
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EOP-001-0
R3.2.
Develop, maintain, and implement a set of plans to mitigate
operating emergencies on the transmission system.
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EOP-001-0
R3.3.
Develop, maintain, and implement a set of plans for load
shedding.
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EOP-001-0
R3.4.
Develop, maintain, and implement a set of plans for system
restoration.
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EOP-001-0
R4.
Each Transmission Operator and Balancing Authority shall have
emergency plans that will enable it to mitigate operating
emergencies. At a minimum, Transmission Operator and
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Balancing Authority emergency plans shall include:
EOP-001-0
R4.1.
Communications protocols to be used during emergencies.
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EOP-001-0
R4.2.
A list of controlling actions to resolve the emergency. Load
reduction, in sufficient quantity to resolve the emergency within
NERC-established timelines, shall be one of the controlling
actions.
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EOP-001-0
R4.3.
The tasks to be coordinated with and among adjacent
Transmission Operators and Balancing Authorities.
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EOP-001-0
R4.4.
Staffing levels for the emergency.
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EOP-001-0
R5.
Each Transmission Operator and Balancing Authority shall
include the applicable elements in Attachment 1-EOP-001-0
when developing an emergency plan.
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EOP-001-0
R6.
The Transmission Operator and Balancing Authority shall
annually review and update each emergency plan. The
Transmission Operator and Balancing Authority shall provide a
copy of its updated emergency plans to its Reliability
Coordinator and to neighboring Transmission Operators and
Balancing Authorities.
TOP
EOP-001-0
R7.
The Transmission Operator and Balancing Authority shall
coordinate its emergency plans with other Transmission
Operators and Balancing Authorities as appropriate. This
coordination includes the following steps, as applicable:
TOP
EOP-001-0
R7.1.
The Transmission Operator and Balancing Authority shall
establish and maintain reliable communications between
interconnected systems.
TOP
EOP-001-0
R7.2.
The Transmission Operator and Balancing Authority shall
arrange new interchange agreements to provide for emergency
capacity or energy transfers if existing agreements cannot be
used.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
46
Standard
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Requirement
Number
Text of Requirement
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TO
TOP
EOP-001-0
R7.3.
The Transmission Operator and Balancing Authority shall
coordinate transmission and generator maintenance schedules,
including outages to the Generator Interconnection Facility, to
maximize capacity or conserve the fuel in short supply. (This
includes water for hydro generators.)
TOP
EOP-001-0
R7.4.
The Transmission Operator and Balancing Authority shall
arrange deliveries of electrical energy or fuel from remote
systems through normal operating channels.
TOP
EOP-003-1
R1.
After taking all other remedial steps, a Transmission Operator or
Balancing Authority operating with insufficient generation or
transmission capacity shall shed customer load rather than risk
an uncontrolled failure of components or cascading outages of
the Interconnection.
TOP
EOP-003-1
R2.
Each Transmission Operator and Balancing Authority shall
establish plans for automatic load shedding for underfrequency
or undervoltage conditions.
TOP
EOP-003-1
R3.
Each Transmission Operator and Balancing Authority shall
coordinate load shedding plans among other interconnected
Transmission Operators and Balancing Authorities.
TOP
EOP-003-1
R4.
A Transmission Operator or Balancing Authority shall consider
one or more of these factors in designing an automatic load
shedding scheme: frequency, rate of frequency decay, voltage
level, rate of voltage decay, or power flow levels.
TOP
EOP-003-1
R5.
A Transmission Operator or Balancing Authority shall
implement load shedding in steps established to minimize the
risk of further uncontrolled separation, loss of generation, or
system shutdown.
TOP
EOP-003-1
R6.
After a Transmission Operator or Balancing Authority Area
separates from the Interconnection, if there is insufficient
generating capacity to restore system frequency following
automatic underfrequency load shedding, the Transmission
Operator or Balancing Authority shall shed additional load.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
47
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
Comments
Generic issue: Need to add Generator
Operator applicability to ensure the
units’ frequency trip set points are
appropriately included in the needed
coordination. This change is required
only if the PRC-024-1 standard under
development now as part of the
Generator Verification drafting team
does not adequately address the issue.
EOP-003-1
R7.
The Transmission Operator, Generator Operator, and Balancing
Authority shall coordinate automatic load shedding throughout
their areas with underfrequency isolation of generating units,
tripping of shunt capacitors, and other automatic actions that
will occur under abnormal frequency, voltage, or power flow
conditions.
TOP
EOP-003-1
R8.
Each Transmission Operator or Balancing Authority shall have
plans for operator-controlled manual load shedding to respond
to real-time emergencies. The Transmission Operator or
Balancing Authority shall be capable of implementing the load
shedding in a timeframe adequate for responding to the
emergency.
TOP
EOP-004-1
R2.
A Reliability Coordinator, Balancing Authority, Transmission
Operator, Generator Operator or Load-Serving Entity shall
promptly analyze Bulk Electric System disturbances on its
system or facilities, including those for the Generator
Interconnection Facility.
GOP
TOP
EOP-004-1
R3.
A Reliability Coordinator, Balancing Authority, Transmission
Operator, Generator Operator or Load-Serving Entity
experiencing a reportable incident shall provide a preliminary
written report to its Regional Reliability Organization and
NERC.
GOP
TOP
EOP-004-1
R3.1.
The affected Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator or Load-Serving
Entity shall submit within 24 hours of the disturbance or
unusual occurrence either a copy of the report submitted to
DOE, or, if no DOE report is required, a copy of the NERC
Interconnection Reliability Operating Limit and Preliminary
Disturbance Report form. Events that are not identified until
some time after they occur shall be reported within 24 hours of
being recognized.
GOP
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
48
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
EOP-004-1
R3.2.
Applicable reporting forms are provided in Attachments 022-1
and 022-2.
GOP
TOP
EOP-004-1
R3.3.
Under certain adverse conditions, e.g., severe weather, it may
not be possible to assess the damage caused by a disturbance
and issue a written Interconnection Reliability Operating Limit
and Preliminary Disturbance Report within 24 hours. In such
cases, the affected Reliability Coordinator, Balancing Authority,
Transmission Operator, Generator Operator, or Load-Serving
Entity shall promptly notify its Regional Reliability
Organization(s) and NERC, and verbally provide as much
information as is available at that time. The affected Reliability
Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, or Load-Serving Entity shall then provide
timely, periodic verbal updates until adequate information is
available to issue a written Preliminary Disturbance Report.
GOP
TOP
EOP-004-1
R3.4.
If, in the judgment of the Regional Reliability Organization,
after consultation with the Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, or LoadServing Entity in which a disturbance occurred, a final report is
required, the affected Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, or LoadServing Entity shall prepare this report within 60 days. As a
minimum, the final report shall have a discussion of the events
and its cause, the conclusions reached, and recommendations to
prevent recurrence of this type of event. The report shall be
subject to Regional Reliability Organization approval.
GOP
TOP
EOP-005-1
R1.
Each Transmission Operator shall have a restoration plan to
reestablish its electric system in a stable and orderly manner in
the event of a partial or total shutdown of its system, including
necessary operating instructions and procedures to cover
emergency conditions, and the loss of vital telecommunications
channels. Each Transmission Operator shall include the
applicable elements listed in Attachment 1-EOP-005 in
developing a restoration plan.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
TOP
49
Standard
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Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
EOP-005-1
R2.
Each Transmission Operator shall review and update its
restoration plan at least annually and whenever it makes changes
in the power system network, and shall correct deficiencies
found during the simulated restoration exercises.
TOP
EOP-005-1
R3.
Each Transmission Operator shall develop restoration plans with
a priority of restoring the integrity of the Interconnection.
TOP
EOP-005-1
R4.
Each Transmission Operator shall coordinate its restoration
plans with the Generator Owners and Balancing Authorities
within its area, its Reliability Coordinator, and neighboring
Transmission Operators and Balancing Authorities.
TOP
EOP-005-1
R5.
Each Transmission Operator and Balancing Authority shall
periodically test its telecommunication facilities needed to
implement the restoration plan.
TOP
EOP-005-1
R6.
Each Transmission Operator and Balancing Authority shall train
its operating personnel in the implementation of the restoration
plan. Such training shall include simulated exercises, if
practicable.
TOP
EOP-005-1
R7.
Each Transmission Operator and Balancing Authority shall
verify the restoration procedure by actual testing or by
simulation.
TOP
EOP-005-1
R8.
Each Transmission Operator shall verify that the number, size,
availability, and location of system blackstart generating units
are sufficient to meet Regional Reliability Organization
restoration plan requirements for the Transmission Operator’s
area.
TOP
EOP-005-1
R9.
The Transmission Operator shall document the Cranking Paths,
including initial switching requirements, between each
blackstart generating unit and the unit(s) to be started and shall
provide this documentation for review by the Regional
Reliability Organization upon request. Such documentation
may include Cranking Path diagrams.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
50
Standard
Number
Requirement
Number
Text of Requirement
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GOP
TO
TOP
EOP-005-1
R10.
The Transmission Operator shall demonstrate, through
simulation or testing, that the blackstart generating units in its
restoration plan can perform their intended functions as required
in the regional restoration plan.
TOP
EOP-005-1
R10.1.
The Transmission Operator shall perform this simulation or
testing at least once every five years.
TOP
EOP-005-1
R11.
Following a disturbance in which one or more areas of the Bulk
Electric System become isolated or blacked out, the affected
Transmission Operators and Balancing Authorities shall begin
immediately to return the Bulk Electric System to normal.
TOP
EOP-005-1
R11.1.
The affected Transmission Operators and Balancing Authorities
shall work in conjunction with their Reliability Coordinator(s)
to determine the extent and condition of the isolated area(s).
TOP
EOP-005-1
R11.2.
The affected Transmission Operators and Balancing Authorities
shall take the necessary actions to restore Bulk Electric System
frequency to normal, including adjusting generation, placing
additional generators on line, or load shedding.
TOP
EOP-005-1
R11.4.
The affected Transmission Operators shall give high priority to
restoration of off-site power to nuclear stations.
TOP
EOP-005-1
R11.5.
The affected Transmission Operators may resynchronize the
isolated area(s) with the surrounding area(s) when the following
conditions are met:
TOP
EOP-005-1
R11.5.1.
Voltage, frequency, and phase angle permit.
TOP
EOP-005-1
R11.5.2.
The size of the area being reconnected and the capacity of the
transmission lines effecting the reconnection and the number of
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
The team identified this as a potential
general issue. However, when one
considers the new requirements
recommended (found in TOP-001 R7
Comment area), the TOP has decisionmaking authority over the Generator
Interconnection Operational Interface,
there is no gap created through this
specific requirement.
51
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Text of Requirement
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Comments
synchronizing points across the system are considered.
EOP-005-1
R11.5.3.
Reliability Coordinator(s) and adjacent areas are notified and
Reliability Coordinator approval is given.
TOP
EOP-005-1
R11.5.4.
Load is shed in neighboring areas, if required, to permit
successful interconnected system restoration.
TOP
EOP-008-0
R1.
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall have a plan to continue reliability
operations in the event its control center becomes inoperable.
The contingency plan must meet the following requirements:
TOP
EOP-008-0
R1.1.
The contingency plan shall not rely on data or voice
communication from the primary control facility to be viable.
TOP
EOP-008-0
R1.2.
The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that there
is an hourly accounting of all schedules.
TOP
EOP-008-0
R1.3.
The contingency plan must address monitoring and control of
critical transmission facilities, Generator Interconnection
Operational Interface, generation control, voltage control, time
and frequency control, control of critical substation devices, and
logging of significant power system events. The plan shall list
the critical facilities.
TOP
EOP-008-0
R1.4.
The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with other
areas.
TOP
EOP-008-0
R1.5.
The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure viability of
the plan.
TOP
EOP-008-0
R1.6.
The plan shall include procedures and responsibilities for
providing annual training to ensure that operating personnel are
able to implement the contingency plans.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
52
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
EOP-008-0
R1.7.
The plan shall be reviewed and updated annually.
TOP
EOP-008-0
R1.8.
Interim provisions must be included if it is expected to take
more than one hour to implement the contingency plan for loss
of primary control facility.
TOP
EOP-009-0
R1.
The Generator Operator of each blackstart generating unit shall
test the startup and operation of each system blackstart
generating unit identified in the BCP as required in the Regional
BCP (Reliability Standard EOP-007-0_R1). Testing records
shall include the dates of the tests, the duration of the tests, and
an indication of whether the tests met Regional BCP
requirements.
EOP-009-0
R2.
The Generator Owner or Generator Operator shall provide
documentation of the test results of the startup and operation of
each blackstart generating unit to the Regional Reliability
Organizations and upon request to NERC.
FAC-001-0
R1.
The Transmission Owner shall document, maintain, and publish
facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Reliability
Organization, subregional, Power Pool, and individual
Transmission Owner planning criteria and facility connection
requirements. The Transmission Owner’s facility connection
requirements shall address connection requirements for:
TO
FAC-001-0
R1.1.
Generation facilities, including the Generator Interconnection
Facility,
TO
FAC-001-0
R1.2.
Transmission facilities, and
TO
FAC-001-0
R1.3.
End-user facilities
TO
FAC-001-0
R2.
The Transmission Owner’s facility connection requirements
shall address, but are not limited to, the following items:
TO
FAC-001-0
R2.1.
Provide a written summary of its plans to achieve the required
system performance as described above throughout the planning
horizon:
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
GOP
GO
GOP
53
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
FAC-001-0
R2.1.1.
Procedures for coordinated joint studies of new facilities and
their impacts on the interconnected transmission systems.
TO
FAC-001-0
R2.1.2.
Procedures for notification of new or modified facilities to
others (those responsible for the reliability of the interconnected
transmission systems) as soon as feasible.
TO
FAC-001-0
R2.1.3.
Voltage level and MW and MVAR capacity or demand at point
of connection.
TO
FAC-001-0
R2.1.4.
Breaker duty and surge protection.
TO
FAC-001-0
R2.1.5.
System protection and coordination.
TO
FAC-001-0
R2.1.6.
Metering and telecommunications.
TO
FAC-001-0
R2.1.7.
Grounding and safety issues.
TO
FAC-001-0
R2.1.8.
Insulation and insulation coordination.
TO
FAC-001-0
R2.1.9.
Voltage, Reactive Power, and power factor control.
TO
FAC-001-0
R2.1.10.
Power quality impacts.
TO
FAC-001-0
R2.1.11.
Equipment Ratings.
TO
FAC-001-0
R2.1.12.
Synchronizing of facilities.
TO
FAC-001-0
R2.1.13.
Maintenance coordination.
TO
FAC-001-0
R2.1.14.
Operational issues (abnormal frequency and voltages).
TO
FAC-001-0
R2.1.15.
Inspection requirements for existing or new facilities.
TO
FAC-001-0
R2.1.16.
Communications and procedures during normal and emergency
operating conditions.
TO
FAC-001-0
R3.
The Transmission Owner shall maintain and update its facility
connection requirements as required. The Transmission Owner
shall make documentation of these requirements available to the
users of the transmission system, the Regional Reliability
Organization, and NERC on request (five business days).
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
Comments
54
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
FAC-002-0
R1.
The Generator Owner, Transmission Owner, Distribution
Provider, and Load-Serving Entity seeking to integrate
generation facilities, transmission facilities, and electricity enduser facilities shall each coordinate and cooperate on its
assessments with its Transmission Planner and Planning
Authority. The assessment shall include:
GO
TO
FAC-002-0
R1.1.
Evaluation of the reliability impact of the new facilities and
their connections on the interconnected transmission systems.
GO
TO
FAC-002-0
R1.2.
Ensurance of compliance with NERC Reliability Standards and
applicable Regional, subregional, Power Pool, and individual
system planning criteria and facility connection requirements.
GO
TO
FAC-002-0
R1.3.
Evidence that the parties involved in the assessment have
coordinated and cooperated on the assessment of the reliability
impacts of new facilities on the interconnected transmission
systems. While these studies may be performed independently,
the results shall be jointly evaluated and coordinated by the
entities involved.
GO
TO
FAC-002-0
R1.4.
Evidence that the assessment included steady-state, shortcircuit, and dynamics studies as necessary to evaluate system
performance in accordance with Reliability Standard TPL-0010.
GO
TO
FAC-002-0
R1.5.
Documentation that the assessment included study assumptions,
system performance, alternatives considered, and jointly
coordinated recommendations.
GO
TO
FAC-002-0
R2.
The Planning Authority, Transmission Planner, Generator
Owner, Transmission Owner, Load-Serving Entity, and
Distribution Provider shall each retain its documentation (of its
evaluation of the reliability impact of the new facilities and their
connections on the interconnected transmission systems) for
three years and shall provide the documentation to the Regional
Reliability Organization(s) Regional Reliability Organization(s)
and NERC on request (within 30 calendar days).
GO
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
Comments
55
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
FAC-003-1
R1.
The Transmission owner and Generator Owner shall prepare,
and keep current, a formal transmission vegetation management
(TVM). The TVMP shall include the Transmission Owner's and
Generator Owner’s objectives, practices, approved procedures,
and work Specifications. 1. ANSI A300, Tree Care Operations
– Tree, Shrub, and Other Woody Plant Maintenance – Standard
Practices, while not a requirement of this standard, is considered
to be an industry best practice.
TO
FAC-003-1
R1.1.
The TVMP shall define a schedule for and the type (aerial,
ground) of ROW vegetation inspections. This schedule should
be flexible enough to adjust for changing conditions. The
inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors
that could impact the relationship of vegetation to the
Transmission Owner’s or Generator Owner’s transmission lines.
TO
FAC-003-1
R1.2.
The Transmission Owner and Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and
any overhead, ungrounded supply conductors, taking into
consideration transmission line voltage, the effects of ambient
temperature on conductor sag under maximum design loading,
and the effects of wind velocities on conductor sway.
Specifically, the Transmission Owner and Generator Owner
shall establish clearances to be achieved at the time of
vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances
identified herein as Clearance 2 to prevent flashover between
vegetation and overhead ungrounded supply conductors.
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
Comments
Applies to the Generator
Interconnection Facility above 200 kV
that exceeds two spans from the
generator property line or are otherwise
deemed critical by the Regional Entity
below 200 kV (subject to the two-span
criteria.)
56
Standard
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Text of Requirement
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GOP
TO
FAC-003-1
R1.2.1.
Clearance 1 — The Transmission Owner and Generator Owner
shall determine and document appropriate clearance distances to
be achieved at the time of transmission vegetation management
work based upon local conditions and the expected time frame
in which the Transmission Owner or Generator Owner plans to
return for future vegetation management work. Local
conditions may include, but are not limited to: operating
voltage, appropriate vegetation management techniques, fire
risk, reasonably anticipated tree and conductor movement,
species types and growth rates, species failure characteristics,
local climate and rainfall patterns, line terrain and elevation,
location of the vegetation within the span, and worker approach
distance requirements. Clearance 1 distances shall be greater
than those defined by Clearance 2 below.
TO
FAC-003-1
R1.2.2.
Clearance 2 — The Transmission Owner and Generator Owner
shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated
electrical operating conditions. These minimum clearance
distances are necessary to prevent flashover between vegetation
and conductors and will vary due to such factors as altitude and
operating voltage. These Transmission Owner-specific and
Generator Owner-specific minimum clearance distances shall be
no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for
Maintenance Methods on Energized Power Lines) and as
specified in its Section 4.2.2.3, Minimum Air Insulation
Distances without Tools in the Air Gap.
TO
FAC-003-1
R1.2.2.1.
Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 5162003, phase-to-ground distances, with appropriate altitude
correction factors applied.
TO
FAC-003-1
R1.2.2.2.
Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 5162003, phase-to-phase voltages, with appropriate altitude
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
Comments
57
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Text of Requirement
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TO
TOP
Comments
correction factors applied.
FAC-003-1
R1.3.
All personnel directly involved in the design and
implementation of the TVMP shall hold appropriate
qualifications and training, as defined by the Transmission
Owner or Generator Owner, to perform their duties.
TO
FAC-003-1
R1.4.
Each Transmission Owner and Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the
protection of the transmission facilities when it identifies
locations on the ROW where the Transmission Owner or
Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
TO
FAC-003-1
R1.5.
Each Transmission Owner and Generator Owner shall establish
and document a process for the immediate communication of
vegetation conditions that present an imminent threat of a
transmission line outage. This is so that action (temporary
reduction in line rating, switching line out of service, etc.) may
be taken until the threat is relieved.
TO
FAC-003-1
R2.
The Transmission Owner and Generator Owner shall create and
implement an annual plan for vegetation management work to
ensure the reliability of the system. The plan shall describe the
methods used, such as manual clearing, mechanical clearing,
herbicide treatment, or other actions. The plan should be flexible
enough to adjust to changing conditions, taking into
consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability
of the transmission systems. Adjustments to the plan shall be
documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits
from landowners or regulatory authorities. Each Transmission
Owner and Generator Owner shall have systems and procedures
for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management
work was completed according to work specifications.
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
58
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Number
Requirement
Number
Text of Requirement
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GOP
TO
FAC-003-1
R3.
The Transmission Owner and Generator Owner shall report
quarterly to its RRO, or the RRO’s designee, sustained
transmission line outages determined by the Transmission
Owner or Generator Owner to have been caused by vegetation.
TO
FAC-003-1
R3.1.
Multiple sustained outages on an individual line, if caused by
the same vegetation, shall be reported as one outage regardless
of the actual number of outages within a 24-hour period.
TO
FAC-003-1
R3.2.
The Transmission Owner or Generator Owner is not required to
report to the RRO, or the RRO’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetationrelated outages that result from vegetation falling into lines from
outside the ROW that result from natural disasters shall not be
considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to,
earthquakes, fires, tornados, hurricanes, landslides, wind shear,
major storms as defined either by the Transmission Owner,
Generator Owner, or an applicable regulatory body, ice storms,
and floods), and (2) Vegetation-related outages due to human or
animal activity shall not be considered reportable (examples of
human or animal activity that could cause a non-reportable
outage include, but are not limited to, logging, animal severing
tree, vehicle contact with tree, arboricultural activities or
horticultural or agricultural activities, or removal or digging of
vegetation).
TO
FAC-003-1
R3.3.
The outage information provided by the Transmission Owner or
Generator Owner to the RRO, or the RRO’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the
date, time and duration of the outage; a description of the cause
of the outage; other pertinent comments; and any
countermeasures taken by the Transmission Owner or Generator
Owner.
TO
FAC-003-1
R3.4.
An outage shall be categorized as one of the following:
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
Comments
59
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
FAC-003-1
R3.4.1.
Category 1 — Grow-ins: Outages caused by vegetation growing
into lines from vegetation inside and/or outside of the ROW;
TO
FAC-003-1
R3.4.2.
Category 2 — Fall-ins: Outages caused by vegetation falling
into lines from inside the ROW;
TO
FAC-003-1
R3.4.3.
Category 3 — Fall-ins: Outages caused by vegetation falling
into lines from outside the ROW.
TO
FAC-008-1
R1.
The Transmission Owner and Generator Owner shall each
document its current methodology used for developing Facility
Ratings (Facility Ratings Methodology) of its solely and jointly
owned Facilities, including the Generator Interconnection
Facility. The methodology shall include all of the following:
GO
TO
FAC-008-1
R1.1.
A statement that a Facility Rating shall equal the most limiting
applicable Equipment Rating of the individual equipment that
comprises that Facility.
GO
TO
FAC-008-1
R1.2.
The method by which the Rating (of major BES equipment that
comprises a Facility) is determined.
GO
TO
FAC-008-1
R1.2.1.
The scope of equipment addressed shall include, but not be
limited to, generators, the Generator Interconnection Facility,
transmission conductors, transformers, relay protective devices,
terminal equipment, and series and shunt compensation devices.
GO
TO
FAC-008-1
R1.2.2.
The scope of Ratings addressed shall include, as a minimum,
both Normal and Emergency Ratings.
GO
TO
FAC-008-1
R1.3.
Consideration of the following:
GO
TO
FAC-008-1
R1.3.1.
Ratings provided by equipment manufacturers.
GO
TO
FAC-008-1
R1.3.2.
Design criteria (e.g., including applicable references to industry
Rating practices such as manufacturer’s warranty, IEEE, ANSI
or other standards).
GO
TO
FAC-008-1
R1.3.3.
Ambient conditions.
GO
TO
FAC-008-1
R1.3.4.
Operating limitations.
GO
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Comments
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FAC-008-1
R1.3.5.
Other assumptions.
GO
TO
FAC-008-1
R2.
The Transmission Owner and Generator Owner shall each make
its Facility Ratings Methodology available for inspection and
technical review by those Reliability Coordinators,
Transmission Operators, Transmission Planners, and Planning
Authorities that have responsibility for the area in which the
associated Facilities are located, within 15 business days of
receipt of a request.
GO
TO
FAC-008-1
R3.
If a Reliability Coordinator, Transmission Operator,
Transmission Planner, or Planning Authority provides written
comments on its technical review of a Transmission Owner’s or
Generator Owner’s Facility Ratings Methodology, the
Transmission Owner or Generator Owner shall provide a written
response to that commenting entity within 45 calendar days of
receipt of those comments. The response shall indicate whether
a change will be made to the Facility Ratings Methodology and,
if no change will be made to that Facility Ratings Methodology,
the reason why.
GO
TO
FAC-009-1
R1.
The Transmission Owner and Generator Owner shall each
establish Facility Ratings for its solely and jointly owned
Facilities, including the Generator Interconnection Facility, that
are consistent with the associated Facility Ratings Methodology.
GO
TO
FAC-009-1
R2.
The Transmission Owner and Generator Owner shall each
provide Facility Ratings for its solely and jointly owned
Facilities, including the Generator Interconnection Facility, that
are existing Facilities, new Facilities, modifications to existing
Facilities and re-ratings of existing Facilities to its associated
Reliability Coordinator(s), Planning Authority(ies),
Transmission Planner(s), and Transmission Operator(s) as
scheduled by such requesting entities.
GO
TO
FAC-014-1
R2.
The Transmission Operator shall establish SOLs (as directed by
its Reliability Coordinator) for its portion of the Reliability
Coordinator Area that are consistent with its Reliability
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Comments
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61
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Coordinator’s SOL Methodology.
FAC-014-1
R5.2.
The Transmission Operator shall provide any SOLs it developed
to its Reliability Coordinator and to the Transmission Service
Providers that share its portion of the Reliability Coordinator
Area.
TOP
INT-004-2
R2.3.
A Reliability Coordinator or Transmission Operator determines
the deviation, regardless of magnitude, to be a reliability
concern and notifies the Purchasing-Selling Entity of that
determination and the reasons.
TOP
IRO-001-1.1
R8.
Transmission Operators, Balancing Authorities, Generator
Operators, Transmission Service Providers, Load-Serving
Entities, and Purchasing-Selling Entities shall comply with
Reliability Coordinator directives unless such actions would
violate safety, equipment, or regulatory or statutory
requirements. Under these circumstances, the Transmission
Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving Entity, or
Purchasing-Selling Entity shall immediately inform the
Reliability Coordinator of the inability to perform the directive
so that the Reliability Coordinator may implement alternate
remedial actions.
IRO-002-1
R3.
Each Reliability Coordinator – or its Transmission Operators
and Balancing Authorities – shall provide, or arrange provisions
for, data exchange to other Reliability Coordinators or
Transmission Operators and Balancing Authorities via a secure
network.
TOP
IRO-004-1
R3.
Each Reliability Coordinator shall, in conjunction with its
Transmission Operators and Balancing Authorities, develop
action plans that may be required, including reconfiguration of
the transmission system, re-dispatching of generation, reduction
or curtailment of Interchange Transactions, or reducing load to
return transmission loading to within acceptable SOLs or
IROLs.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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IRO-004-1
R4.
Each Transmission Operator, Balancing Authority,
Transmission Owner, Generator Owner, Generator Operator,
and Load-Serving Entity in the Reliability Coordinator Area
shall provide information required for system studies, such as
critical facility status, Load, generation, operating reserve
projections, and known Interchange Transactions. This
information shall be available by 1200 Central Standard Time
for the Eastern Interconnection and 1200 Pacific Standard Time
for the Western Interconnection.
IRO-004-1
R7.
Each Transmission Operator, Balancing Authority, and
Transmission Service Provider shall comply with the directives
of its Reliability Coordinator based on the next day assessments
in the same manner in which it would comply during real time
operating events.
TOP
IRO-005-2
R3.
As portions of the transmission system approach or exceed
SOLs or IROLs, the Reliability Coordinator shall work with its
Transmission Operators and Balancing Authorities to evaluate
and assess any additional Interchange Schedules that would
violate those limits. If a potential or actual IROL violation
cannot be avoided through proactive intervention, the Reliability
Coordinator shall initiate control actions or emergency
procedures to relieve the violation without delay, and no longer
than 30 minutes. The Reliability Coordinator shall ensure all
resources, including load shedding, are available to address a
potential or actual IROL violation.
TOP
IRO-005-2
R6.
Each Reliability Coordinator shall ensure its Transmission
Operators and Balancing Authorities are aware of Geo-Magnetic
Disturbance (GMD) forecast information and assist as needed in
the development of any required response plans.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
The team considered whether an
existing GOP-specific requirement
existed to close what could have been a
gap in coverage. The team concluded
that IRO-001-1 R8 addresses this issue.
Therefore, no gap exists.
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IRO-005-2
R8.
Each Reliability Coordinator shall monitor system frequency
and its Balancing Authorities’ performance and direct any
necessary rebalancing to return to CPS and DCS compliance.
The Transmission Operators and Balancing Authorities shall
utilize all resources, including firm load shedding, as directed by
its Reliability Coordinator to relieve the emergent condition.
IRO-005-2
R9.
The Reliability Coordinator shall coordinate with Transmission
Operators, Balancing Authorities, and Generator Operators as
needed to develop and implement action plans to mitigate
potential or actual SOL, IROL, CPS, or DCS violations. The
Reliability Coordinator shall coordinate pending generation and
transmission maintenance outages, including the Generator
Interconnection Facility, with Transmission Operators,
Balancing Authorities, and Generator Operators as needed in
both the real time and next-day reliability analysis timeframes.
IRO-005-2
R12.
Whenever a Special Protection System that may have an interBalancing Authority, or inter-Transmission Operator impact
(e.g., could potentially affect transmission flows resulting in a
SOL or IROL violation) is armed, the Reliability Coordinators
shall be aware of the impact of the operation of that Special
Protection System on inter-area flows. The Transmission
Operator shall immediately inform the Reliability Coordinator
of the status of the Special Protection System including any
degradation or potential failure to operate as expected.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
GO
GOP
TO
TOP
Comments
TOP
GOP
TOP
TOP
General issue with generators: For
generating units that participate in
some fashion in a Special Protection
System or Remedial Action System
that has supporting relaying or control
equipment to enable this functionality,
the GOP must notify the TOP of a
status or condition change of the
equipment. Therefore, a new
requirement specific to the GOP must
be added:
Rx. The Generator Operator shall
immediately inform the Transmission
Operator of the status of the Special
Protection System, including any
degradation or potential failure to
operate as expected for SPS relay or
control equipment under its control.
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IRO-005-2
R13.
Each Reliability Coordinator shall ensure that all Transmission
Operators, Balancing Authorities, Generator Operators,
Transmission Service Providers, Load-Serving Entities, and
Purchasing-Selling Entities operate to prevent the likelihood that
a disturbance, action, or non-action in its Reliability Coordinator
Area will result in a SOL or IROL violation in another area of
the Interconnection. In instances where there is a difference in
derived limits, the Reliability Coordinator and its Transmission
Operators, Balancing Authorities, Generator Operators,
Transmission Service Providers, Load-Serving Entities, and
Purchasing-Selling Entities shall always operate the Bulk
Electric System to the most limiting parameter.
IRO-005-2
R15.
Each Reliability Coordinator who foresees a transmission
problem (such as an SOL or IROL violation, loss of reactive
reserves, etc.) within its Reliability Coordinator Area shall issue
an alert to all impacted Transmission Operators and Balancing
Authorities in its Reliability Coordinator Area without delay.
The receiving Reliability Coordinator shall disseminate this
information to its impacted Transmission Operators and
Balancing Authorities. The Reliability Coordinator shall notify
all impacted Transmission Operators, Balancing Authorities,
when the transmission problem has been mitigated.
IRO-005-2
R17.
When an IROL or SOL is exceeded, the Reliability Coordinator
shall evaluate the local and wide-area impacts, both real-time
and post-contingency, and determine if the actions being taken
are appropriate and sufficient to return the system to within
IROL in thirty minutes. If the actions being taken are not
appropriate or sufficient, the Reliability Coordinator shall direct
the Transmission Operator, Balancing Authority, Generator
Operator, or Load-Serving Entity to return the system to within
IROL or SOL.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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GOP
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Comments
TOP
TOP
GOP
TOP
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MOD-010-0
R1.
The Transmission Owners, Transmission Planners, Generator
Owners (for plant and the Generator Interconnection Facility),
and Resource Planners (specified in the data requirements and
reporting procedures of MOD-011-0_R1) shall provide
appropriate equipment characteristics, system data, and existing
and future Interchange Schedules in compliance with its
respective Interconnection Regional steady-state modeling and
simulation data requirements and reporting procedures as
defined in Reliability Standard MOD-011-0_R 1.
GO
TO
MOD-010-0
R2.
The Transmission Owners, Transmission Planners, Generator
Owners (for plant and the Generator Interconnection Facility),
and Resource Planners (specified in the data requirements and
reporting procedures of MOD-011-0_R1) shall provide this
steady-state modeling and simulation data to the Regional
Reliability Organizations, NERC, and those entities specified
within Reliability Standard MOD-011-0_R 1. If no schedule
exists, then these entities shall provide the data on request (30
calendar days).
GO
TO
MOD-012-0
R1.
The Transmission Owners, Transmission Planners, Generator
Owners (for plant and the Generator Interconnection Facility),
and Resource Planners (specified in the data requirements and
reporting procedures of MOD-013-0_R1) shall provide
appropriate equipment characteristics and system data in
compliance with the respective Interconnection-wide Regional
dynamics system modeling and simulation data requirements
and reporting procedures as defined in Reliability Standard
MOD-013-0_R1.
GO
TO
MOD-012-0
R2.
The Transmission Owners, Transmission Planners, Generator
Owners (for plant and the Generator Interconnection Facility),
and Resource Planners (specified in the data requirements and
reporting procedures of MOD-013-0_R4) shall provide
dynamics system modeling and simulation data to its Regional
Reliability Organization(s), NERC, and those entities specified
within the applicable reporting procedures identified in
Reliability Standard MOD-013-0_R 1. If no schedule exists,
GO
TO
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November 16, 2009
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Comments
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then these entities shall provide data on request (30 calendar
days).
NUC-001-1
R1.
The Nuclear Plant Generator Operator shall provide the
proposed NPIRs in writing to the applicable Transmission
Entities and shall verify receipt
GO
GOP
TO
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NUC-001-1
R2.
The Nuclear Plant Generator Operator and the applicable
Transmission Entities shall have in effect one or more
Agreements1 that include mutually agreed to NPIRs and
document how the Nuclear Plant Generator Operator and the
applicable Transmission Entities shall address and implement
these NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R3.
Per the Agreements developed in accordance with this standard,
the applicable Transmission Entities shall incorporate the NPIRs
into their planning analyses of the electric system and shall
communicate the results of these analyses to the Nuclear Plant
Generator Operator.
GO
GOP
TO
TOP
NUC-001-1
R4.
Per the Agreements developed in accordance with this standard,
the applicable Transmission Entities shall:
GO
GOP
TO
TOP
NUC-001-1
R4.1.
Incorporate the NPIRs into their operating analyses of the
electric system.
GO
GOP
TO
TOP
NUC-001-1
R4.2.
Operate the electric system to meet the NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R4.3.
Inform the Nuclear Plant Generator Operator when the ability to
assess the operation of the electric system affecting NPIRs is
lost.
GO
GOP
TO
TOP
NUC-001-1
R5.
The Nuclear Plant Generator Operator shall operate per the
Agreements developed in accordance with this standard.
NUC-001-1
R6.
Per the Agreements developed in accordance with this standard,
the applicable Transmission Entities and the Nuclear Plant
Generator Operator shall coordinate outages and maintenance
activities which affect the NPIRs.
TO
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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NUC-001-1
R7.
Per the Agreements developed in accordance with this standard,
the Nuclear Plant Generator Operator shall inform the
applicable Transmission Entities of actual or proposed changes
to nuclear plant design, configuration, operations, limits,
protection systems, or capabilities that may impact the ability of
the electric system to meet the NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R8.
Per the Agreements developed in accordance with this standard,
the applicable Transmission Entities shall inform the Nuclear
Plant Generator Operator of actual or proposed changes to
electric system design, configuration, operations, limits,
protection systems, or capabilities that may impact the ability of
the electric system to meet the NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R9.
The Nuclear Plant Generator Operator and the applicable
Transmission Entities shall include, as a minimum, the
following elements within the agreement(s) identified in R2:
GO
GOP
TO
TOP
NUC-001-1
R9.1.
Administrative elements:
GO
GOP
TO
TOP
NUC-001-1
R9.1.1.
Definitions of key terms used in the agreement.
GO
GOP
TO
TOP
NUC-001-1
R9.1.2.
Names of the responsible entities, organizational relationships,
and responsibilities related to the NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R9.1.3.
A requirement to review the agreement(s) at least every three
years.
GO
GOP
TO
TOP
NUC-001-1
R9.1.4.
A dispute resolution mechanism.
GO
GOP
TO
TOP
NUC-001-1
R9.2.
Technical requirements and analysis:
GO
GOP
TO
TOP
NUC-001-1
R9.2.1.
Identification of parameters, limits, configurations, and
operating scenarios included in the NPIRs and, as applicable,
procedures for providing any specific data not provided within
the agreement.
GO
GOP
TO
TOP
NUC-001-1
R9.2.2.
Identification of facilities, components, and configuration
restrictions that are essential for meeting the NPIRs.
GO
GOP
TO
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Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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NUC-001-1
R9.2.3.
Types of planning and operational analyses performed
specifically to support the NPIRs, including the frequency of
studies and types of Contingencies and scenarios required.
GO
GOP
TO
TOP
NUC-001-1
R9.3.
Operations and maintenance coordination:
GO
GOP
TO
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NUC-001-1
R9.3.1.
Designation of ownership of electrical facilities at the interface
between the electric system and the nuclear plant and
responsibilities for operational control coordination and
maintenance of these facilities.
GO
GOP
TO
TOP
NUC-001-1
R9.3.2.
Identification of any maintenance requirements for equipment
not owned or controlled by the Nuclear Plant Generator
Operator that are necessary to meet the NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R9.3.3.
Coordination of testing, calibration and maintenance of on-site
and off-site power supply systems and related components.
GO
GOP
TO
TOP
NUC-001-1
R9.3.4.
Provisions to address mitigating actions needed to avoid
violating NPIRs and to address periods when responsible
Transmission Entity loses the ability to assess the capability of
the electric system to meet the NPIRs. These provisions shall
include responsibility to notify the Nuclear Plant Generator
Operator within a specified time frame.
GO
GOP
TO
TOP
NUC-001-1
R9.3.5.
Provision to consider nuclear plant coping times required by the
NPIRs and their relation to the coordination of grid and nuclear
plant restoration following a nuclear plant loss of Off-site
Power.
GO
GOP
TO
TOP
NUC-001-1
R9.3.6.
Coordination of physical and cyber security protection of the
Bulk Electric System at the nuclear plant interface to ensure
each asset is covered under at least one entity’s plan.
GO
GOP
TO
TOP
NUC-001-1
R9.3.7.
Coordination of the NPIRs with transmission system Special
Protection Systems and underfrequency and undervoltage load
shedding programs.
GO
GOP
TO
TOP
NUC-001-1
R9.4.
Communications and training:
GO
GOP
TO
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Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
69
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Requirement
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NUC-001-1
R9.4.1.
Provisions for communications between the Nuclear Plant
Generator Operator and Transmission Entities, including
communications protocols, notification time requirements, and
definitions of terms.
GO
GOP
TO
TOP
NUC-001-1
R9.4.2.
Provisions for coordination during an off-normal or emergency
event affecting the NPIRs, including the need to provide timely
information explaining the event, an estimate of when the
system will be returned to a normal state, and the actual time the
system is returned to normal.
GO
GOP
TO
TOP
NUC-001-1
R9.4.3.
Provisions for coordinating investigations of causes of
unplanned events affecting the NPIRs and developing solutions
to minimize future risk of such events.
GO
GOP
TO
TOP
NUC-001-1
R9.4.4.
Provisions for supplying information necessary to report to
government agencies, as related to NPIRs.
GO
GOP
TO
TOP
NUC-001-1
R9.4.5.
Provisions for personnel training, as related to NPIRs.
GO
GOP
TO
TOP
PER-001-0
R1.
Each Transmission Operator and Balancing Authority shall
provide operating personnel with the responsibility and
authority to implement real-time actions to ensure the stable and
reliable operation of the Bulk Electric System.
TOP
PER-002-0
R1.
Each Transmission Operator, Generator Operator, and
Balancing Authority shall be staffed with adequately trained
operating personnel.
TOP
PER-002-0
R2.
Each Transmission Operator and Balancing Authority shall have
a training program for all operating personnel that are in:
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
Add R2 to PER-001-0 as follows:
R2. Each Generator Operator shall
provide operating personnel with the
responsibility and authority to
implement real-time actions to ensure
the stable and reliable operation of the
Generation Facility and Generation
Interconnection Facility, and the
responsibility and authority to follow
the directives of reliability authorities
including the Transmission Operator
and Balancing Authority.
To ensure complete coverage for the
training of personnel with
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Comments
responsibility for operating the
Generator Interconnection Facilities, a
new requirement is needed:
Add R3 as follows:
R3. Each Generator Operator shall
implement an initial and continuing
training program for all operating
personnel that are responsible for
operating the Generator
Interconnection Facility that verifies
the personnel’s ability and
understanding to operate the equipment
in a reliable manner.
PER-002-0
R2.1.
Positions that have the primary responsibility, either directly or
through communications with others, for the real-time operation
of the interconnected Bulk Electric System.
TOP
PER-002-0
R2.2.
Positions directly responsible for complying with NERC
standards.
TOP
PER-002-0
R3.
For personnel identified in Requirement R2, the Transmission
Operator and Balancing Authority shall provide a training
program meeting the following criteria:
TOP
PER-002-0
R3.1.
A set of training program objectives must be defined, based on
NERC and Regional Reliability Organization standards, entity
operating procedures, and applicable regulatory requirements.
These objectives shall reference the knowledge and
competencies needed to apply those standards, procedures, and
requirements to normal, emergency, and restoration conditions
for the Transmission Operator and Balancing Authority
operating positions.
TOP
PER-002-0
R3.2.
The training program must include a plan for the initial and
continuing training of Transmission Operator and Balancing
Authority operating personnel. That plan shall address
knowledge and competencies required for reliable system
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Comments
operations.
PER-002-0
R3.3.
The training program must include training time for all
Transmission Operator and Balancing Authority operating
personnel to ensure their operating proficiency.
TOP
PER-002-0
R3.4.
Training staff must be identified, and the staff must be
competent in both knowledge of system operations and
instructional capabilities.
TOP
PER-002-0
R4.
For personnel identified in Requirement R2, each Transmission
Operator and Balancing Authority shall provide its operating
personnel at least five days per year of training and drills using
realistic simulations of system emergencies, in addition to other
training required to maintain qualified operating personnel.
TOP
PER-003-0
R1.
Each Transmission Operator, Balancing Authority, and
Reliability Coordinator shall staff all operating positions that
meet both of the following criteria with personnel that are
NERC-certified for the applicable functions:
TOP
PER-003-0
R1.1.
Positions that have the primary responsibility, either directly or
through communications with others, for the real-time operation
of the interconnected Bulk Electric System.
TOP
PER-003-0
R1.2.
Positions directly responsible for complying with NERC
standards.
TOP
PRC-001-1
R1.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall be familiar with the purpose and
limitations of protection system schemes applied in its area,
including those for the Generator Interconnection Facility.
GOP
TOP
PRC-001-1
R2.
Each Generator Operator and Transmission Operator shall
notify reliability entities of relay or equipment failures,
including those for the Generator Interconnection Facility, as
follows:
GOP
TOP
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November 16, 2009
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PRC-001-1
R2.1.
If a protective relay or equipment failure reduces system
reliability, the Generator Operator shall notify its Transmission
Operator and Host Balancing Authority. The Generator
Operator shall take corrective action as soon as possible.
PRC-001-1
R2.2.
If a protective relay or equipment failure reduces system
reliability, the Transmission Operator shall notify its Reliability
Coordinator and affected Transmission Operators and Balancing
Authorities. The Transmission Operator shall take corrective
action as soon as possible.
PRC-001-1
R3.
A Generator Operator or Transmission Operator shall coordinate
new protective systems and changes, including those for the
Generator Interconnection Facility, as follows.
GOP
PRC-001-1
R3.1.
Each Generator Operator shall coordinate all new protective
systems and all protective system changes, including those for
the Generator Interconnection Facility, with its Transmission
Operator and Host Balancing Authority.
GOP
PRC-001-1
R3.2.
Each Transmission Operator shall coordinate all new protective
systems and all protective system changes with neighboring
Transmission Operators and Balancing Authorities.
TOP
PRC-001-1
R4.
Each Transmission Operator shall coordinate protection systems
on major transmission lines and interconnections with
neighboring Generator Operators, Transmission Operators, and
Balancing Authorities.
TOP
PRC-001-1
R5.
A Generator Operator or Transmission Operator shall coordinate
changes in generation, transmission, load or operating
conditions, including those for the Generator Interconnection
Facility, that could require changes in the protection systems of
others:
GOP
PRC-001-1
R5.1.
Each Generator Operator shall notify its Transmission Operator
in advance of changes in generation or operating conditions,
including those for the Generator Interconnection Facility, that
could require changes in the Transmission Operator’s protection
GOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
GOP
TOP
TOP
TOP
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systems.
PRC-001-1
R5.2.
Each Transmission Operator shall notify neighboring
Transmission Operators in advance of changes in generation,
transmission, load, or operating conditions that could require
changes in the other Transmission Operators’ protection
systems.
TOP
PRC-001-1
R6.
Each Transmission Operator and Balancing Authority shall
monitor the status of each Special Protection System in their
area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.
TOP
PRC-004-1
R1.
The Transmission Owner and any Distribution Provider that
owns a transmission Protection System shall each analyze its
transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future
Misoperations of a similar nature according to the Regional
Reliability Organization’s procedures developed for Reliability
Standard PRC-003 Requirement 1.
PRC-004-1
R2.
The Generator Owner shall analyze its generator Protection
System Misoperations, including those for the Generator
Interconnection Facility, and shall develop and implement a
Corrective Action Plan to avoid future Misoperations of a
similar nature according to the Regional Reliability
Organization’s procedures developed for PRC-003 R1.
GO
PRC-004-1
R3.
The Transmission Owner, any Distribution Provider that owns a
transmission Protection System, and the Generator Owner shall
each provide to its Regional Reliability Organization,
documentation of its Misoperations analyses and Corrective
Action Plans according to the Regional Reliability
Organization’s procedures developed for PRC-003 R1.
GO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TO
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74
Standard
Number
Requirement
Number
Text of Requirement
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TO
PRC-005-1
R1.
Each Transmission Owner and any Distribution Provider that
owns a transmission Protection System and each Generator
Owner that owns a generation Protection System, including
those for the Generator Interconnection Facility, shall have a
Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The
program shall include:
GO
TO
PRC-005-1
R1.1.
Maintenance and testing intervals and their basis.
GO
TO
PRC-005-1
R1.2.
Summary of maintenance and testing procedures.
GO
TO
PRC-005-1
R2.
Each Transmission Owner and any Distribution Provider that
owns a transmission Protection System and each Generator
Owner that owns a generation Protection System, including
those for the Generator Interconnection Facility, shall provide
documentation of its Protection System maintenance and testing
program and the implementation of that program to its Regional
Reliability Organization on request (within 30 calendar days).
The documentation of the program implementation shall
include:
GO
TO
PRC-005-1
R2.1.
Evidence Protection System devices were maintained and tested
within the defined intervals.
GO
TO
PRC-005-1
R2.2.
Date each Protection System device was last tested/maintained.
GO
TO
PRC-007-0
R1.
The Transmission Owner and Distribution Provider with a
UFLS program (as required by its Regional Reliability
Organization) shall ensure that its UFLS program is consistent
with its Regional Reliability Organization’s UFLS program
requirements.
TO
PRC-007-0
R2.
The Transmission Owner, Transmission Operator, Distribution
Provider, and Load-Serving Entity that owns or operates a
UFLS program (as required by its Regional Reliability
Organization) shall provide, and annually update, its
underfrequency data as necessary for its Regional Reliability
Organization to maintain and update a UFLSprogram database.
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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75
Standard
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Requirement
Number
Text of Requirement
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PRC-007-0
R3.
The Transmission Owner and Distribution Provider that owns a
UFLS program (as required by its Regional Reliability
Organization) shall provide its documentation of that UFLS
program to its Regional Reliability Organization on request (30
calendar days).
TO
PRC-008-0
R1.
The Transmission Owner and Distribution Provider with a
UFLS program (as required by its Regional Reliability
Organization) shall have a UFLS equipment maintenance and
testing program in place. This UFLS equipment maintenance
and testing program shall include UFLS equipment
identification, the schedule for UFLS equipment testing, and the
schedule for UFLS equipment maintenance.
TO
PRC-008-0
R2.
The Transmission Owner and Distribution Provider with a
UFLS program (as required by its Regional Reliability
Organization) shall implement its UFLS equipment maintenance
and testing program and shall provide UFLS maintenance and
testing program results to its Regional Reliability Organization
and NERC on request (within 30 calendar days).
TO
PRC-009-0
R1.
The Transmission Owner, Transmission Operator, Load-Serving
Entity, and Distribution Provider that owns or operates a UFLS
program (as required by its Regional Reliability Organization)
shall analyze and document its UFLS program performance in
accordance with its Regional Reliability Organization’s UFLS
program. The analysis shall address the performance of UFLS
equipment and program effectiveness following system events
resulting in system frequency excursions below the initializing
set points of the UFLS program. The analysis shall include, but
not be limited to:
TO
TOP
PRC-009-0
R1.1.
A description of the event including initiating conditions.
TO
TOP
PRC-009-0
R1.2.
A review of the UFLS set points and tripping times.
TO
TOP
PRC-009-0
R1.3.
A simulation of the event.
TO
TOP
PRC-009-0
R1.4.
A summary of the findings.
TO
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Standard
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Requirement
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Text of Requirement
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PRC-009-0
R2.
The Transmission Owner, Transmission Operator, Load-Serving
Entity, and Distribution Provider that owns or operates a UFLS
program (as required by its Regional Reliability Organization)
shall provide documentation of the analysis of the UFLS
program to its Regional Reliability Organization and NERC on
request 90 calendar days after the system event.
TO
TOP
PRC-010-0
R1.
The Load-Serving Entity, Transmission Owner, Transmission
Operator, and Distribution Provider that owns or operates a
UVLS program shall periodically (at least every five years or as
required by changes in system conditions) conduct and
document an assessment of the effectiveness of the UVLS
program. This assessment shall be conducted with the
associated Transmission Planner(s) and Planning Authority(ies).
TO
TOP
PRC-010-0
R1.1.
This assessment shall include, but is not limited to:
TO
TOP
PRC-010-0
R1.1.1.
Coordination of the UVLS programs with other protection and
control systems in the Region and with other Regional
Reliability Organizations, as appropriate.
TO
TOP
PRC-010-0
R1.1.2.
Simulations that demonstrate that the UVLS programs
performance is consistent with Reliability Standards TPL-001-0,
TPL-002-0, TPL-003-0 and TPL-004-0.
TO
TOP
PRC-010-0
R1.1.3.
A review of the voltage set points and timing.
TO
TOP
PRC-010-0
R2.
The Load-Serving Entity, Transmission Owner, Transmission
Operator, and Distribution Provider that owns or operates a
UVLS program shall provide documentation of its current
UVLS program assessment to its Regional Reliability
Organization and NERC on request (30 calendar days).
TO
TOP
PRC-011-0
R1.
The Transmission Owner and Distribution Provider that owns a
UVLS system shall have a UVLS equipment maintenance and
testing program in place. This program shall include:
TO
PRC-011-0
R1.1.
The UVLS system identification which shall include but is not
limited to:
TO
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Standard
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Requirement
Number
Text of Requirement
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PRC-011-0
R1.1.1.
Relays.
TO
PRC-011-0
R1.1.2.
Instrument transformers.
TO
PRC-011-0
R1.1.3.
Communications systems, where appropriate.
TO
PRC-011-0
R1.1.4.
Batteries.
TO
PRC-011-0
R1.2.
Documentation of maintenance and testing intervals and their
basis.
TO
PRC-011-0
R1.3.
Summary of testing procedure.
TO
PRC-011-0
R1.4.
Schedule for system testing.
TO
PRC-011-0
R1.5.
Schedule for system maintenance.
TO
PRC-011-0
R1.6.
Date last tested/maintained.
TO
PRC-011-0
R2.
The Transmission Owner and Distribution Provider that owns a
UVLS system shall provide documentation of its UVLS
equipment maintenance and testing program and the
implementation of that UVLS equipment maintenance and
testing program to its Regional Reliability Organization and
NERC on request (within 30 calendar days).
TO
PRC-015-0
R1.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall maintain a list of and provide
data for existing and proposed SPSs as specified in Reliability
Standard PRC-013-0_R 1.
GO
TO
PRC-015-0
R2.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall have evidence it reviewed new
or functionally modified SPSs in accordance with the Regional
Reliability Organization’s procedures as defined in Reliability
Standard PRC-012-0_R1 prior to being placed in service.
GO
TO
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November 16, 2009
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Standard
Number
Requirement
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Text of Requirement
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PRC-015-0
R3.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall provide documentation of SPS
data and the results of studies that show compliance of new or
functionally modified SPSs with NERC Reliability Standards
and Regional Reliability Organization criteria to affected
Regional Reliability Organizations and NERC on request
(within 30 calendar days).
GO
TO
PRC-016-0.1
R1.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall analyze its SPS operations and
maintain a record of all misoperations in accordance with the
Regional SPS review procedure specified in Reliability Standard
PRC-012-0_R1.
GO
TO
PRC-016-0.1
R2.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall take corrective actions to avoid
future misoperations.
GO
TO
PRC-016-0.1
R3.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall provide documentation of the
misoperation analyses and the corrective action plans to its
Regional Reliability Organization and NERC on request (within
90 calendar days).
GO
TO
PRC-017-0
R1.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall have a system maintenance and
testing program(s) in place. The program(s) shall include:
GO
TO
PRC-017-0
R1.1.
SPS identification shall include but is not limited to:
GO
TO
PRC-017-0
R1.1.1.
Relays.
GO
TO
PRC-017-0
R1.1.2.
Instrument transformers.
GO
TO
PRC-017-0
R1.1.3.
Communications systems, where appropriate.
GO
TO
PRC-017-0
R1.1.4.
Batteries.
GO
TO
PRC-017-0
R1.2.
Documentation of maintenance and testing intervals and their
basis.
GO
TO
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November 16, 2009
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Comments
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Standard
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Requirement
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Text of Requirement
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PRC-017-0
R1.3.
Summary of testing procedure.
GO
TO
PRC-017-0
R1.4.
Schedule for system testing.
GO
TO
PRC-017-0
R1.5.
Schedule for system maintenance.
GO
TO
PRC-017-0
R1.6.
Date last tested/maintained.
GO
TO
PRC-017-0
R2.
The Transmission Owner, Generator Owner, and Distribution
Provider that owns an SPS shall provide documentation of the
program and its implementation to the appropriate Regional
Reliability Organizations and NERC on request (within 30
calendar days).
GO
TO
PRC-018-1
R1.
Each Transmission Owner and Generator Owner required to
install DMEs by its Regional Reliability Organization
(reliability standard PRC-002 Requirements 1-3) shall have
DMEs installed that meet the following requirements:
GO
TO
PRC-018-1
R1.1.
Internal Clocks in DME devices shall be synchronized to within
2 milliseconds or less of Universal Coordinated Time scale
(UTC)
GO
TO
PRC-018-1
R1.2.
Recorded data from each Disturbance shall be retrievable for ten
calendar days.
GO
TO
PRC-018-1
R2.
The Transmission Owner and Generator Owner shall each
install DMEs in accordance with its Regional Reliability
Organization’s installation requirements (reliability standard
PRC-002 Requirements 1 through 3).
GO
TO
PRC-018-1
R3.
The Transmission Owner and Generator Owner shall each
maintain, and report to its Regional Reliability Organization on
request, the following data on the DMEs installed to meet that
region’s installation requirements (reliability standard PRC-002
Requirements1.1, 2.1 and 3.1):
GO
TO
PRC-018-1
R3.1.
Type of DME (sequence of event recorder, fault recorder, or
dynamic disturbance recorder).
GO
TO
PRC-018-1
R3.2.
Make and model of equipment.
GO
TO
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November 16, 2009
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Standard
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Requirement
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Text of Requirement
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PRC-018-1
R3.3.
Installation location.
GO
TO
PRC-018-1
R3.4.
Operational status.
GO
TO
PRC-018-1
R3.5.
Date last tested.
GO
TO
PRC-018-1
R3.6.
Monitored elements, such as transmission circuit, bus section,
etc.
GO
TO
PRC-018-1
R3.7.
Monitored devices, such as circuit breaker, disconnect status,
alarms, etc.
GO
TO
PRC-018-1
R3.8.
Monitored electrical quantities, such as voltage, current, etc.
GO
TO
PRC-018-1
R4.
The Transmission Owner and Generator Owner shall each
provide Disturbance data (recorded by DMEs) in accordance
with its Regional Reliability Organization’s requirements
(reliability standard PRC-002 Requirement 4).
GO
TO
PRC-018-1
R5.
The Transmission Owner and Generator Owner shall each
archive all data recorded by DMEs for Regional Reliability
Organization-identified events for at least three years.
GO
TO
PRC-018-1
R6.
Each Transmission Owner and Generator Owner that is required
by its Regional Reliability Organization to have DMEs shall
have a maintenance and testing program for those DMEs that
includes:
GO
TO
PRC-018-1
R6.1.
Maintenance and testing intervals and their basis.
GO
TO
PRC-018-1
R6.2.
Summary of maintenance and testing procedures.
GO
TO
PRC-021-1
R1.
Each Transmission Owner and Distribution Provider that owns a
UVLS program to mitigate the risk of voltage collapse or
voltage instability in the BES shall annually update its UVLS
data to support the Regional UVLS program database. The
following data shall be provided to the Regional Reliability
Organization for each installed UVLS system:
TO
PRC-021-1
R1.1.
Size and location of customer load, or percent of connected
load, to be interrupted.
TO
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November 16, 2009
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PRC-021-1
R1.2.
Corresponding voltage set points and overall scheme clearing
times.
TO
PRC-021-1
R1.3.
Time delay from initiation to trip signal.
TO
PRC-021-1
R1.4.
Breaker operating times.
TO
PRC-021-1
R1.5.
Any other schemes that are part of or impact the UVLS
programs such as related generation protection, islanding
schemes, automatic load restoration schemes, UFLS and Special
Protection Systems.
TO
PRC-021-1
R2.
Each Transmission Owner and Distribution Provider that owns a
UVLS program shall provide its UVLS program data to the
Regional Reliability Organization within 30 calendar days of a
request.
TO
PRC-022-1
R1.
Each Transmission Operator, Load-Serving Entity, and
Distribution Provider that operates a UVLS program to mitigate
the risk of voltage collapse or voltage instability in the BES
shall analyze and document all UVLS operations and
Misoperations. The analysis shall include:
TOP
PRC-022-1
R1.1.
A description of the event including initiating conditions.
TOP
PRC-022-1
R1.2.
A review of the UVLS set points and tripping times.
TOP
PRC-022-1
R1.3.
A simulation of the event, if deemed appropriate by the
Regional Reliability Organization. For most events, analysis of
sequence of events may be sufficient and dynamic simulations
may not be needed.
TOP
PRC-022-1
R1.4.
A summary of the findings.
TOP
PRC-022-1
R1.5.
For any Misoperation, a Corrective Action Plan to avoid future
Misoperations of a similar nature.
TOP
PRC-022-1
R2.
Each Transmission Operator, Load-Serving Entity, and
Distribution Provider that operates a UVLS program shall
provide documentation of its analysis of UVLS program
performance to its Regional Reliability Organization within 90
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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Text of Requirement
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Comments
calendar days of a request.
TOP-001-1
R1.
Each Transmission Operator shall have the responsibility and
clear decision-making authority to take whatever actions are
needed to ensure the reliability of its area and shall exercise
specific authority to alleviate operating emergencies.
TOP
TOP-001-1
R2.
Each Transmission Operator shall take immediate actions to
alleviate operating emergencies including curtailing
transmission service or energy schedules, operating equipment
(e.g., generators, phase shifters, breakers), shedding firm load,
etc.
TOP
TOP-001-1
R3.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall comply with reliability directives
issued by the Reliability Coordinator, and each Balancing
Authority and Generator Operator shall comply with reliability
directives issued by the Transmission Operator, unless such
actions would violate safety, equipment, regulatory or statutory
requirements. Under these circumstances the Transmission
Operator, Balancing Authority, or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission
Operator of the inability to perform the directive so that the
Reliability Coordinator or Transmission Operator can
implement alternate remedial actions.
TOP-001-1
R5.
Each Transmission Operator shall inform its Reliability
Coordinator and any other potentially affected Transmission
Operators of real-time or anticipated emergency conditions, and
take actions to avoid, when possible, or mitigate the emergency.
TOP-001-1
R6.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall render all available emergency
assistance to others as requested, provided that the requesting
entity has implemented its comparable emergency procedures,
unless such actions would violate safety, equipment, or
regulatory or statutory requirements.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
GOP
TOP
TOP
GOP
Gap identified: covered by new
requirement outlined in TOP-001- R7
Comment area.
Gap identified: covered by new
requirement outlined in TOP-001- R7
Comment area.
TOP
83
Standard
Number
TOP-001-1
Requirement
Number
R7.
Text of Requirement
Each Transmission Operator and Generator Operator shall not
remove Bulk Electric System facilities, including the Generator
Interconnection Facility, from service if removing those
facilities would burden neighboring systems unless:
GO
GOP
GOP
TO
TOP
Comments
TOP
Need to add new requirements to
address interconnection facilities:
Add R9 as follows:
R9. The Generator Operator shall
coordinate the operation of its
Generator Interconnection Facility with
the Transmission Operator to whom it
interconnects in order to preserve
Interconnection reliability with respect
to the following:
Switching elements
Outage planning
Real-time or anticipated
emergency conditions
Other conditions mutually
agreed upon by the Generator
Operator and Transmission
Operator
Add R10 as follows:
R10. The Transmission Operator shall
have decision-making authority over
operation of the Generator
Interconnection Operational Interface at
all times in order to preserve
Interconnection reliability.
TOP-001-1
R7.1.
For a generator outage, including the Generator Interconnection
Facility, the Generator Operator shall notify and coordinate with
the Transmission Operator. The Transmission Operator shall
notify the Reliability Coordinator and other affected
Transmission Operators, and coordinate the impact of removing
the Bulk Electric System facility.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
GOP
TOP
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Standard
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Requirement
Number
Text of Requirement
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TOP-001-1
R7.2.
For a transmission facility, the Transmission Operator shall
notify and coordinate with its Reliability Coordinator. The
Transmission Operator shall notify other affected Transmission
Operators, and coordinate the impact of removing the Bulk
Electric System facility.
TOP-001-1
R7.3.
When time does not permit such notifications and coordination,
or when immediate action is required to prevent a hazard to the
public, lengthy customer service interruption, or damage to
facilities, the Generator Operator shall notify the Transmission
Operator, and the Transmission Operator shall notify its
Reliability Coordinator and adjacent Transmission Operators, at
the earliest possible time.
TOP-001-1
R8.
During a system emergency, the Balancing Authority and
Transmission Operator shall immediately take action to restore
the Real and Reactive Power Balance. If the Balancing
Authority or Transmission Operator is unable to restore Real
and Reactive Power Balance it shall request emergency
assistance from the Reliability Coordinator. If corrective action
or emergency assistance is not adequate to mitigate the Real and
Reactive Power Balance, then the Reliability Coordinator,
Balancing Authority, and Transmission Operator shall
implement firm load shedding.
TOP
TOP-002-2
R1.
Each Balancing Authority and Transmission Operator shall
maintain a set of current plans that are designed to evaluate
options and set procedures for reliable operation through a
reasonable future time period. In addition, each Balancing
Authority and Transmission Operator shall be responsible for
using available personnel and system equipment to implement
these plans to ensure that interconnected system reliability will
be maintained.
TOP
TOP-002-2
R2.
Each Balancing Authority and Transmission Operator shall
ensure its operating personnel participate in the system planning
and design study processes, so that these studies contain the
operating personnel perspective and system operating personnel
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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TOP
GOP
TOP
85
Standard
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Requirement
Number
Text of Requirement
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GOP
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Comments
are aware of the planning purpose.
TOP-002-2
R3.
Each Load-Serving Entity and Generator Operator shall
coordinate (where confidentiality agreements allow) its currentday, next-day, and seasonal operations, including for the
Generator Interconnection Facility, with its Host Balancing
Authority and Transmission Service Provider. Each Balancing
Authority and Transmission Service Provider shall coordinate
its current-day, next-day, and seasonal operations with its
Transmission Operator.
TOP-002-2
R4.
Each Balancing Authority and Transmission Operator shall
coordinate (where confidentiality agreements allow) its currentday, next-day, and seasonal planning and operations with
neighboring Balancing Authorities and Transmission Operators
and with its Reliability Coordinator, so that normal
Interconnection operation will proceed in an orderly and
consistent manner.
TOP
TOP-002-2
R5.
Each Balancing Authority and Transmission Operator shall plan
to meet scheduled system configuration, generation dispatch,
interchange scheduling and demand patterns.
TOP
TOP-002-2
R6.
Each Balancing Authority and Transmission Operator shall plan
to meet unscheduled changes in system configuration and
generation dispatch (at a minimum N-1 Contingency planning)
in accordance with NERC, Regional Reliability Organization,
subregional, and local reliability requirements.
TOP
TOP-002-2
R10.
Each Balancing Authority and Transmission Operator shall plan
to meet all System Operating Limits (SOLs) and
Interconnection Reliability Operating Limits (IROLs).
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
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86
Standard
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Requirement
Number
Text of Requirement
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GOP
TOP-002-2
R11.
The Transmission Operator shall perform seasonal, next-day,
and current-day Bulk Electric System studies to determine
SOLs. Neighboring Transmission Operators shall utilize
identical SOLs for common facilities. The Transmission
Operator shall update these Bulk Electric System studies as
necessary to reflect current system conditions; and shall make
the results of Bulk Electric System studies available to the
Transmission Operators, Balancing Authorities (subject to
confidentiality requirements), and to its Reliability Coordinator.
TOP-002-2
R13.
At the request of the Balancing Authority or Transmission
Operator, a Generator Operator shall perform generating real
and reactive capability verification that shall include, among
other variables, weather, ambient air and water conditions, and
fuel quality and quantity, and provide the results to the
Balancing Authority or Transmission Operator operating
personnel as requested.
GOP
TOP-002-2
R14.
Generator Operators shall, without any intentional time delay,
notify their Balancing Authority and Transmission Operator of
changes in capabilities and characteristics including but not
limited to:
GOP
TOP-002-2
R14.1.
Changes in real output capabilities.
GOP
TOP-002-2
R14.2.
Automatic Voltage Regulator status and mode setting. (Retired
August 1, 2007)
GOP
TOP-002-2
R15.
Generation Operators shall, at the request of the Balancing
Authority or Transmission Operator, provide a forecast of
expected real power output to assist in operations planning (e.g.,
a seven-day forecast of real output).
GOP
TOP-002-2
R16.
Subject to standards of conduct and confidentiality agreements,
Transmission Operators shall, without any intentional time
delay, notify their Reliability Coordinator and Balancing
Authority of changes in capabilities and characteristics
including but not limited to:
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TO
TOP
Comments
TOP
Add R14.3 as follows:
Changes in Generator Interconnection
Facility Status
TOP
87
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
TOP-002-2
R16.1.
Changes in transmission facility status.
TOP
TOP-002-2
R16.2.
Changes in transmission facility rating.
TOP
TOP-002-2
R17.
Balancing Authorities and Transmission Operators shall,
without any intentional time delay, communicate the
information described in the requirements R1 to R16 above to
their Reliability Coordinator.
TOP
TOP-002-2
R18.
Neighboring Balancing Authorities, Transmission Operators,
Generator Operators, Transmission Service Providers, and
Load-Serving Entities shall use uniform line identifiers when
referring to transmission facilities of an interconnected network
and for the Generator Interconnection Facility.
TOP-002-2
R19.
Each Balancing Authority and Transmission Operator shall
maintain accurate computer models utilized for analyzing and
planning system operations.
TOP-003-0
R1.
Generator Operators and Transmission Operators shall provide
planned outage information, including information for the
Generator Interconnection Facility.
GOP
TOP
TOP-003-0
R1.1.
Each Generator Operator shall provide outage information daily
to its Transmission Operator for scheduled generator outages
planned for the next day (any foreseen outage of a generator
greater than 50 MW) or for the Generator Interconnection
Facility. The Transmission Operator shall establish the outage
reporting requirements.
GOP
TOP
TOP-003-0
R1.2.
Each Transmission Operator shall provide outage information
daily to its Reliability Coordinator, and to affected Balancing
Authorities and Transmission Operators for scheduled generator
and bulk transmission outages planned for the next day (any
foreseen outage of a transmission line or transformer greater
than 100 kV or generator greater than 50 MW) that may
collectively cause or contribute to an SOL or IROL violation or
a regional operating area limitation. The Reliability Coordinator
shall establish the outage reporting requirements.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
GOP
Comments
TOP
TOP
TOP
88
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
TOP-003-0
R1.3.
Such information shall be available by 1200 Central Standard
Time for the Eastern Interconnection and 1200 Pacific Standard
Time for the Western Interconnection.
TOP-003-0
R2.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall plan and coordinate scheduled outages
of system voltage regulating equipment, such as automatic
voltage regulators on generators, supplementary excitation
control, synchronous condensers, shunt and series capacitors,
reactors, etc., among affected Balancing Authorities and
Transmission Operators as required.
GOP
TOP
TOP-003-0
R3.
Each Transmission Operator, Balancing Authority, and
Generator Operator shall plan and coordinate scheduled outages
of telemetering and control equipment and associated
communication channels between the affected areas.
GOP
TOP
TOP-004-2
R1.
Each Transmission Operator shall operate within the
Interconnection Reliability Operating Limits (IROLs) and
System Operating Limits (SOLs).
TOP
TOP-004-2
R2.
Each Transmission Operator shall operate so that instability,
uncontrolled separation, or cascading outages will not occur as a
result of the most severe single contingency.
TOP
TOP-004-2
R3.
Each Transmission Operator shall operate to protect against
instability, uncontrolled separation, or cascading outages
resulting from multiple outages, as specified by its Reliability
Coordinator.
TOP
TOP-004-2
R4.
If a Transmission Operator enters an unknown operating state
(i.e. any state for which valid operating limits have not been
determined), it will be considered to be in an emergency and
shall restore operations to respect proven reliable power system
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
TOP
To close gap for GOP operation of its
Generator Interconnection Facilities, a
new requirement is needed:
Add R7 as follows:
Rx. The Generator Operator shall
operate its Generator Interconnection
Facility within its applicable ratings.
89
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
Comments
limits within 30 minutes.
TOP-004-2
R5.
Each Transmission Operator shall make every effort to remain
connected to the Interconnection. If the Transmission Operator
determines that by remaining interconnected, it is in imminent
danger of violating an IROL or SOL, the Transmission Operator
may take such actions, as it deems necessary, to protect its area.
TOP
TOP-004-2
R6.
Transmission Operators, individually and jointly with other
Transmission Operators, shall develop, maintain, and implement
formal policies and procedures to provide for transmission
reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and
intra-Regional reliability, including:
TOP
TOP-004-2
R6.1.
Monitoring and controlling voltage levels and real and reactive
power flows.
TOP
TOP-004-2
R6.2.
Switching transmission elements.
TOP
TOP-004-2
R6.3.
Planned outages of transmission elements.
TOP
TOP-004-2
R6.4.
Responding to IROL and SOL violations.
TOP
TOP-005-1.1
R1.
Each Transmission Operator and Balancing Authority shall
provide its Reliability Coordinator with the operating data that
the Reliability Coordinator requires to perform operational
reliability assessments and to coordinate reliable operations
within the Reliability Coordinator Area.
TOP
TOP-005-1.1
R3.
Upon request, each Balancing Authority and Transmission
Operator shall provide to other Balancing Authorities and
Transmission Operators with immediate responsibility for
operational reliability, the operating data that are necessary to
allow these Balancing Authorities and Transmission Operators
to perform operational reliability assessments and to coordinate
reliable operations. Balancing Authorities and Transmission
Operators shall provide the types of data as listed in Attachment
1-TOP-005-0 “Electric System Reliability Data,” unless
otherwise agreed to by the Balancing Authorities and
TOP
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Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
Comments
Transmission Operators with immediate responsibility for
operational reliability.
TOP-006-1
R1.
Each Transmission Operator and Balancing Authority shall
know the status of all generation and transmission resources
available for use.
TOP-006-1
R1.1.
Each Generator Operator shall inform its Host Balancing
Authority and the Transmission Operator of all generation
resources available for use.
TOP-006-1
R1.2.
Each Transmission Operator and Balancing Authority shall
inform the Reliability Coordinator and other affected Balancing
Authorities and Transmission Operators of all generation and
transmission resources available for use.
TOP
TOP-006-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall monitor applicable transmission line
status, real and reactive power flows, voltage, load-tap-changer
settings, and status of rotating and static reactive resources.
TOP
TOP-006-1
R3.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall provide appropriate technical
information concerning protective relays to their operating
personnel.
TOP
TOP-006-1
R4.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have information, including weather
forecasts and past load patterns, available to predict the system’s
near-term load pattern.
TOP
TOP-006-1
R5.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall use monitoring equipment to bring to
the attention of operating personnel important deviations in
operating conditions and to indicate, if appropriate, the need for
corrective action.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
TOP
GOP
91
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
TOP-006-1
R6.
Each Balancing Authority and Transmission Operator shall use
sufficient metering of suitable range, accuracy and sampling rate
(if applicable) to ensure accurate and timely monitoring of
operating conditions under both normal and emergency
situations.
TOP
TOP-006-1
R7.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall monitor system frequency.
TOP
TOP-007-0
R1.
A Transmission Operator shall inform its Reliability
Coordinator when an IROL or SOL has been exceeded and the
actions being taken to return the system to within limits.
TOP
TOP-007-0
R2.
Following a Contingency or other event that results in an IROL
violation, the Transmission Operator shall return its
transmission system to within IROL as soon as possible, but not
longer than 30 minutes.
TOP
TOP-007-0
R3.
A Transmission Operator shall take all appropriate actions up to
and including shedding firm load, or directing the shedding of
firm load, in order to comply with Requirement R 2.
TOP
TOP-008-1
R1.
The Transmission Operator experiencing or contributing to an
IROL or SOL violation shall take immediate steps to relieve the
condition, which may include shedding firm load.
TOP
TOP-008-1
R2.
Each Transmission Operator shall operate to prevent the
likelihood that a disturbance, action, or inaction will result in an
IROL or SOL violation in its area or another area of the
Interconnection. In instances where there is a difference in
derived operating limits, the Transmission Operator shall always
operate the Bulk Electric System to the most limiting parameter.
TOP
TOP-008-1
R3.
The Transmission Operator shall disconnect the affected facility
if the overload on a transmission facility or abnormal voltage or
reactive condition persists and equipment is endangered. In
doing so, the Transmission Operator shall notify its Reliability
Coordinator and all neighboring Transmission Operators
impacted by the disconnection prior to switching, if time
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
Add companion GOP requirement to
ensure clarity:
Add R5 as follows:
R5. The Generator Operator shall
disconnect the Generator
Interconnection Facility when safety is
92
Standard
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Number
Text of Requirement
GO
GOP
TO
TOP
permits, otherwise, immediately thereafter.
jeopardized or the overload or
abnormal voltage or reactive condition
persists and generating equipment or
the Generator Interconnection Facility
is endangered. In doing so, the
Generator Operator shall notify its
Transmission Operator and Balancing
Authority impacted by the
disconnection prior to switching, if
time permits, otherwise, immediately
thereafter.
TOP-008-1
R4.
The Transmission Operator shall have sufficient information
and analysis tools to determine the cause(s) of SOL violations.
This analysis shall be conducted in all operating timeframes.
The Transmission Operator shall use the results of these
analyses to immediately mitigate the SOL violation.
TOP
VAR-001-1
R1.
Each Transmission Operator, individually and jointly with other
Transmission Operators, shall ensure that formal policies and
procedures are developed, maintained, and implemented for
monitoring and controlling voltage levels and Mvar flows
within their individual areas and with the areas of neighboring
Transmission Operators.
TOP
VAR-001-1
R2.
Each Transmission Operator shall acquire sufficient reactive
resources within its area to protect the voltage levels under
normal and Contingency conditions. This includes the
Transmission Operator’s share of the reactive requirements of
interconnecting transmission circuits.
TOP
VAR-001-1
R3.
The Transmission Operator shall specify criteria that exempts
generators from compliance with the requirements defined in
Requirement 4, and Requirement 6.1.
TOP
VAR-001-1
R3.1.
Each Transmission Operator shall maintain a list of generators
in its area that are exempt from following a voltage or Reactive
Power schedule.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
93
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
VAR-001-1
R3.2.
For each generator that is on this exemption list, the
Transmission Operator shall notify the associated Generator
Owner.
TOP
VAR-001-1
R4.
Each Transmission Operator shall specify a voltage or Reactive
Power schedule at the interconnection between the generator
facility and the Transmission Owner's facilities to be maintained
by each generator. The Transmission Operator shall provide the
voltage or Reactive Power schedule to the associated Generator
Operator and direct the Generator Operator to comply with the
schedule in automatic voltage control mode (AVR in service
and controlling voltage).
TOP
VAR-001-1
R6.
The Transmission Operator shall know the status of all
transmission Reactive Power resources, including the status of
voltage regulators and power system stabilizers.
TOP
VAR-001-1
R6.1.
When notified of the loss of an automatic voltage regulator
control, the Transmission Operator shall direct the Generator
Operator to maintain or change either its voltage schedule or its
Reactive Power schedule.
TOP
VAR-001-1
R7.
The Transmission Operator shall be able to operate or direct the
operation of devices necessary to regulate transmission voltage
and reactive flow.
TOP
VAR-001-1
R8.
Each Transmission Operator shall operate or direct the operation
of capacitive and inductive reactive resources within its area –
including reactive generation scheduling; transmission line,
Generator Interconnection Facility, and reactive resource
switching; and, if necessary, load shedding – to maintain system
and Interconnection voltages within established limits.
TOP
VAR-001-1
R9.
Each Transmission Operator shall maintain reactive resources to
support its voltage under first Contingency conditions.
TOP
VAR-001-1
R9.1.
Each Transmission Operator shall disperse and locate the
reactive resources so that the resources can be applied
effectively and quickly when Contingencies occur.
TOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
94
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
TO
TOP
VAR-001-1
R10.
Each Transmission Operator shall correct IROL or SOL
violations resulting from reactive resource deficiencies (IROL
violations must be corrected within 30 minutes) and complete
the required IROL or SOL violation reporting.
TOP
VAR-001-1
R11.
After consultation with the Generator Owner regarding
necessary step-up transformer tap changes, the Transmission
Operator shall provide documentation to the Generator Owner
specifying the required tap changes, a timeframe for making the
changes, and technical justification for these changes.
TOP
VAR-001-1
R12.
The Transmission Operator shall direct corrective action,
including load reduction, necessary to prevent voltage collapse
when reactive resources are insufficient.
TOP
VAR-002-1.1a
R1.
The Generator Operator shall operate each generator connected
to the interconnected transmission system in the automatic
voltage control mode (automatic voltage regulator in service and
controlling voltage) unless the Generator Operator has notified
the Transmission Operator.
GOP
VAR-002-1.1a
R2.
Unless exempted by the Transmission Operator, each Generator
Operator shall maintain the generator voltage or Reactive Power
output (within applicable Facility Ratings. [1] as directed by the
Transmission Operator
GOP
VAR-002-1.1a
R2.1.
When a generator’s automatic voltage regulator is out of
service, the Generator Operator shall use an alternative method
to control the generator voltage and reactive output to meet the
voltage or Reactive Power schedule directed by the
Transmission Operator.
GOP
VAR-002-1.1a
R2.2.
When directed to modify voltage, the Generator Operator shall
comply or provide an explanation of why the schedule cannot be
met.
GOP
VAR-002-1.1a
R3.
Each Generator Operator shall notify its associated
Transmission Operator as soon as practical, but within 30
minutes of any of the following:
GOP
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
Comments
95
Standard
Number
Requirement
Number
Text of Requirement
GO
GOP
VAR-002-1.1a
R3.1.
A status or capability change on any generator Reactive Power
resource, including the status of each automatic voltage
regulator and power system stabilizer and the expected duration
of the change in status or capability.
GOP
VAR-002-1.1a
R3.2.
A status or capability change on any other Reactive Power
resources under the Generator Operator’s control, including the
Generator Interconnection Facility, and the expected duration of
the change in status or capability.
GOP
VAR-002-1.1a
R4.
The Generator Owner shall provide the following to its
associated Transmission Operator and Transmission Planner
within 30 calendar days of a request.
GO
VAR-002-1.1a
R4.1.
For generator step-up transformers and auxiliary transformers
with primary voltages equal to or greater than the generator
terminal voltage:
GO
VAR-002-1.1a
R4.1.1.
Tap settings.
GO
VAR-002-1.1a
R4.1.2.
Available fixed tap ranges.
GO
VAR-002-1.1a
R4.1.3.
Impedance data.
GO
VAR-002-1.1a
R4.1.4.
The +/- voltage range with step-change in % for load-tap
changing transformers.
GO
VAR-002-1.1a
R5.
After consultation with the Transmission Operator regarding
necessary step-up transformer tap changes, the Generator Owner
shall ensure that transformer tap positions are changed
according to the specifications provided by the Transmission
Operator, unless such action would violate safety, an equipment
rating, a regulatory requirement, or a statutory requirement.
GO
VAR-002-1.1a
R5.1.
If the Generator Operator can’t comply with the Transmission
Operator’s specifications, the Generator Operator shall notify
the Transmission Operator and shall provide the technical
justification.
Generator Requirements at the Transmission Interface Final Report
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TOP
Comments
GOP
96
Appendix 2 — Proposed Revisions to the Statement of
Compliance Registry Criteria
Generator Requirements at the Transmission Interface Final Report
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97
Statement of Compliance Registry Criteria
(Revision 6.0)
Summary
Since becoming the Electric Reliability Organization (ERO), NERC has initiated a program to
identify candidate organizations for its compliance registry. The program, conducted by NERC
and the Regional Entities 5, will also confirm the functions and information now on file for
currently-registered organizations. NERC and the Regional Entities have the obligation to
identify and register all entities that meet the criteria for inclusion in the compliance registry, as
further explained in the balance of this document.
This document describes how NERC will identify organizations that may be candidates for
registration and assign them to the compliance registry.
Organizations will be responsible to register and to comply with approved reliability standards to
the extent that they are owners, operators, and users of the bulk power system, perform a
function listed in the functional types identified in Section II of this document, and are material
to the reliable operation of the interconnected bulk power system as defined by the criteria and
notes set forth in this document. NERC will apply the following principles to the compliance
registry:
In order to carry out its responsibilities related to enforcement of Reliability
Standards, NERC must identify the owners, operators, and users of the bulk power
system who have a material impact 6 on the bulk power system through a compliance
registry. NERC and the Regional Entities will make their best efforts to identify all
owners, users and operators who have a material reliability impact on the bulk power
system in order to develop a complete and current registry list. The registry will be
updated as required and maintained on an on-going basis.
Organizations listed in the compliance registry are responsible and will be monitored
for compliance with applicable mandatory reliability standards. They will be subject
to NERC's and the Regional Entities' compliance and enforcement programs.
NERC and Regional Entities will not monitor nor hold those not in the registry
responsible for compliance with the standards. An entity which is not initially placed
on the registry, but which is identified subsequently as having a material reliability
impact, will be added to the registry. Such entity will not be subject to a sanction or
penalty by NERC or the Regional Entity for actions or inactions prior to being placed
5
The term “Regional Entities” includes Cross-Border Regional Entities.
The criteria for determining whether an entity will be placed on the registry are set forth in the balance of this
document. At any time a person may recommend in writing, with supporting reasons, to the director of compliance
that an organization be added to or removed from the compliance registry, pursuant to NERC ROP 501.1.3.5.
6
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
98
on the registry, but may be required to comply with a remedial action directive or
mitigation plan in order to become compliant with applicable standards. After such
entity has been placed on the compliance registry, it shall be responsible for
complying with Reliability Standards and may be subject to sanctions or penalties as
well as any remedial action directives and mitigation plans required by the Regional
Entities or NERC for future violations, including any failure to follow a remedial
action directive or mitigation plan to become compliant with Reliability Standards.
Required compliance by a given organization with the standards will begin the later
of (i) inclusion of that organization in the compliance registry and (ii) approval by the
appropriate governmental authority of mandatory reliability standards applicable to
the entity.
Entities responsible for funding NERC and the Regional Entities have been identified in the
budget documents filed with FERC. Presence on or absence from the compliance registry has no
bearing on an entity’s independent responsibility for funding NERC and the Regional Entities.
Background
In 2005, NERC and the Regional Entities conducted a voluntary organization registration
program limited to balancing authorities, planning authorities, regional reliability organizations,
reliability coordinators, transmission operators, and transmission planners. The list of the entities
that were registered constitutes what NERC considered at that time as its compliance registry.
NERC has recently initiated a broader program to identify additional organizations potentially
eligible to be included in the compliance registry and to confirm the information of organizations
currently on file. NERC believes this is a prudent activity at this time because:
7
As of July 20, 2006, NERC was certified as the ERO created for the U.S. by the Energy
Policy Act of 2005 (EPAct) and FERC Order 672. NERC has also filed with Canadian
authorities for similar recognition in their respective jurisdictions.
FERC’s Order 672 directs that owners, operators and users of the bulk power system
shall be registered with the ERO and the appropriate Regional Entities.
As the ERO, NERC has filed its current reliability standards with FERC and with
Canadian authorities. As accepted and approved by FERC and appropriate Canadian
authorities, the reliability standards are no longer voluntary, and organizations that do not
fully comply with them may face penalties or other sanctions determined and levied by
NERC or the Regional Entities.
NERC’s reliability standards include compliance requirements for additional reliability
function types beyond the six types registered by earlier registration programs.
Based on selection as the ERO, the extension and expansion of NERC’s current
registration program 7 is the means by which NERC and the Regional Entities will plan,
manage and execute reliability standard compliance oversight of owners, operators, and
users of the bulk power system.
See: NERC ERO Application; Exhibit C; Section 500 – Organization Registration and Certification.
Generator Requirements at the Transmission Interface Final Report
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99
Organizations listed in the compliance registry are subject to NERC’s and the Regional
Entities’ compliance and enforcement programs.
Statement of Issue
As the ERO, NERC intends to comprehensively and thoroughly protect the reliability of the grid.
To support this goal NERC will include in its compliance registry each entity that NERC
concludes can materially impact the reliability of the bulk power system. However, the potential
costs and effort of ensuring that every organization potentially within the scope of “owner,
operator, and user of the bulk power system” becomes registered while ignoring their impact
upon reliability, would be disproportionate to the improvement in reliability that would
reasonably be anticipated from doing so.
NERC wishes to identify as many organizations as possible that may need to be listed in its
compliance registry. Identifying these organizations is necessary and prudent at this time for the
purpose of determining resource needs, both at the NERC and Regional Entity level, and to
begin the process of communication with these entities regarding their potential responsibilities
and obligations. NERC and the Regional Entities believe that primary candidate entities can be
identified at this time, while other entities can be identified later, as and when needed. Selection
principles and criteria for the identification of these initial entities are required. This list will
become the “Initial Non-binding Organization Registration List”. With FERC having made the
approved Reliability Standards enforceable, this list becomes the NERC Compliance Registry.
Resolution
NERC and the Regional Entities have identified two principles they believe are key to the entity
selection process. These are:
1. There needs to be consistency between regions and across the continent with respect to
which entities are registered, and;
2. Any entity reasonably deemed material to the reliability of the bulk power system will be
registered, irrespective of other considerations.
To address the second principle the Regional Entities, working with NERC, will identify and
register any entity they deem material to the reliability of the bulk power system.
In order to promote consistency, NERC and the Regional Entities intend to use the following
criteria as the basis for determining whether particular entities should be identified as candidates
for registration. All organizations meeting or exceeding the criteria will be identified as
candidates.
The following four groups of criteria (Sections I-IV) plus the statements in Section V will
provide guidance regarding an entity’s registration status:
Section I determines if the entity is an owner, operator, or user of the bulk power system
and, hence, a candidate for organization registration.
Generator Requirements at the Transmission Interface Final Report
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Section II uses NERC’s current functional type definitions to provide an initial
determination of the functional types for which the entities identified in Section I should
be considered for registration.
Section III lists the criteria regarding smaller entities; these criteria can be used to forego
the registration of entities that were selected to be considered for registration pursuant to
Sections I and II and, if circumstances change, for later removing entities from the
registration list that no longer meet the relevant criteria.
Section IV — additional criteria for joint registration. Joint registration criteria may be
used by Joint Action Agencies, Generation and Transmission Cooperatives and other
entities which agree upon a clear division of compliance responsibility for Reliability
Standards by written agreement. Pursuant to FERC’s directive in paragraph 107 of Order
No. 693, rules pertaining to joint registration and Joint Registration Organizations will
now be found in Sections 501 and 507 of the NERC Rules of Procedure.
I.
Entities that use, own or operate elements of the bulk electric system as established by
NERC’s approved definition of bulk electric system below are (i) owners, operators, and
users of the bulk power system and (ii) candidates for registration:
“As defined by the Regional Reliability Organization, the electrical
generation resources, transmission lines, interconnections with neighboring
systems, and associated equipment, generally operated at voltages of 100
kV or higher. Radial transmission facilities serving only load with one
transmission source are generally not included in this definition. 8”
II.
Entities identified in Part I above will be categorized as registration candidates who may be
subject to registration under one or more appropriate functional entity types based on a
comparison of the functions the entity normally performs against the following function
type definitions:
Function Type
Acronym
Definition/Discussion
Balancing
Authority
BA
The responsible entity that integrates resource plans ahead of time,
maintains load-interchange-generation balance within a BA area, and
supports Interconnection frequency in real-time.
Distribution
Provider
DP
Provides and operates the “wires” between the transmission system
and the end-use customer. For those end-use customers who are
served at transmission voltages, the Transmission Owner also serves
as the DP. Thus, the DP is not defined by a specific voltage, but
rather as performing the Distribution function at any voltage.
8
However, ownership of radial transmission facilities intended to be covered by the vegetation management
standard (applicable to transmission lines 200 kV and above) would be included in this definition.
Generator Requirements at the Transmission Interface Final Report
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101
Function Type
Acronym
Definition/Discussion
Generator
Operator
GOP
The entity that operates generating unit(s) and the Generator
Interconnection Facility and performs the functions of supplying
energy and interconnected operations services.
Generator Owner
GO
Entity that owns and maintains generating units, including its
Generator Interconnection Facility.
Interchange
Authority
IA
Load-Serving
Entity
LSE
The responsible entity that authorizes implementation
of valid and balanced Interchange Schedules between
Balancing Authority Areas, and ensures communication
of Interchange information for reliability assessment purposes.
Secures energy and transmission service (and related interconnected
operations services) to serve the electrical demand and energy
requirements of its end-use customers.
Planning
Authority
PA
The responsible entity that coordinates and integrates transmission
facility and service plans, resource plans, and protection systems.
PurchasingSelling Entity
PSE
The entity that purchases or sells and takes title to energy, capacity,
and interconnected operations services. PSE may be affiliated or
unaffiliated merchants and may or may not own generating facilities.
Reliability
Coordinator
RC
The entity that is the highest level of authority who is responsible for
the reliable operation of the bulk power system, has the wide area
view of the bulk power system, and has the operating tools, processes
and procedures, including the authority to prevent or mitigate
emergency operating situations in both next-day analysis and realtime operations. The RC has the purview that is broad enough to
enable the calculation of interconnection reliability operating limits,
which may be based on the operating parameters of transmission
systems beyond any Transmission Operator’s vision.
Reserve Sharing
Group
RSG
A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply operating
reserves required for each BA’s use in recovering from contingencies
within the group. Scheduling energy from an adjacent BA to aid
recovery need not constitute reserve sharing provided the transaction
is ramped in over a period the supplying party could reasonably be
expected to load generation in (e.g., ten minutes). If the transaction is
ramped in quicker, (e.g., between zero and ten minutes) then, for the
purposes of disturbance control performance, the areas become a
RSG.
Generator Requirements at the Transmission Interface Final Report
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102
Function Type
Acronym
Definition/Discussion
Resource
Planner
RP
The entity that develops a long-term (generally one year and beyond)
plan for the resource adequacy of specific loads (customer demand
and energy requirements) within a PA area.
Transmission
Owner
TO
The entity that owns and maintains transmission facilities.
Transmission
Operator
TOP
The entity responsible for the reliability of its local transmission
system and operates or directs the operations of the transmission
facilities.
Transmission
Planner
TP
The entity that develops a long-term (generally one year and beyond)
plan for the reliability (adequacy) of the interconnected bulk electric
transmission systems within its portion of the PA area.
Transmission
Service Provider
TSP
The entity that administers the transmission tariff and provides
transmission service to transmission customers under applicable
transmission service agreements.
III. Entities identified in Part II above as being subject to registration as an LSE, DP, GO, GOP,
TO, or TOP should be excluded from the registration list for these functions if they do not
meet any of the criteria listed below:
III(a) Load-serving Entity:
Electrical load must be accounted for at the bulk power system level to properly plan
and account for the load in the operation of the bulk power system. Load-serving
entities will be registered regardless of whether they own or operate physical power
system assets 9 as follows:
III.a.1
Load-serving entity owning and/or operating physical power system assets
whose peak load is > 25 MW and load is otherwise unaccounted for by
another registered Load-serving entity as described in the exclusion below,
or;
III.a.2
Load-serving entity not owning and/or operating physical power system
assets whose peak load is > 25 MW and load is otherwise unaccounted for
by another registered Load-serving entity as described in the exclusion
below, or;
III.a.3
Load-serving entity is designated as the responsible entity for facilities
that are part of a required underfrequency load shedding (UFLS) program
9
Entities not owning and/or operating physical power system assets that are responsible for serving retail end-use
loads will not be required to comply with reliability standards related to asset ownership or operation.
Generator Requirements at the Transmission Interface Final Report
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103
designed, installed, and operated for the protection of the bulk power
system, or;
III.a.4
Load-serving entity is designated as the responsible entity for facilities
that are part of a required undervoltage load shedding (UVLS) program
designed, installed, and operated for the protection of the bulk power
system.
[Exclusion: A load-serving entity will not be registered based on these
criteria if responsibilities for compliance with approved NERC reliability
standards or associated requirements including reporting have been
transferred by written agreement to another entity that has registered for
the appropriate function for the transferred responsibilities, such as a
load-serving entity, balancing authority, transmission operator, G&T
cooperative or joint action agency as described in Sections 501 and 507
of the NERC Rules of Procedure.]
III(b) Distribution Provider:
III.b.1
Distribution provider system serving >25 MW of peak load that is directly
connected to the bulk power system.
[Exclusion: A distribution provider will not be registered based on this
criterion if responsibilities for compliance with approved NERC reliability
standards or associated requirements including reporting have been
transferred by written agreement to another entity that has registered for
the appropriate function for the transferred responsibilities, such as a
load-serving entity, balancing authority, transmission operator, G&T
cooperative, or joint action agency as described in Sections 501 and 507
of the NERC Rules of Procedure.] or;
III.b.2
Distribution provider is the responsible entity that owns, controls, or
operates facilities that are part of any of the following protection systems
or programs designed, installed, and operated for the protection of the bulk
power system:
a required UFLS program.
a required UVLS program.
a required special protection system.
a required transmission protection system.
[Exclusion: A distribution provider will not be registered based on these
criteria if responsibilities for compliance with approved NERC reliability
standards or associated requirements including reporting have been
transferred by written agreement to another entity that has registered for
the appropriate function for the transferred responsibilities, such as a
load-serving entity, balancing authority, transmission operator, G&T
cooperative, or joint action agency as described in Sections 501 and 507
of the NERC Rules of Procedure.]
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
104
III(c) Generator Owner/Operator:
III.c.1
Individual generating unit > 20 MVA (gross nameplate rating) and is
directly connected to the bulk power system, or;
III.c.2
Generating plant/facility > 75 MVA (gross aggregate nameplate rating) or
when the entity has responsibility for any facility consisting of one or
more units that are connected to the bulk power system at a common bus
with total generation above 75 MVA gross nameplate rating, or;
III.c.3
Any generator, regardless of size, that is a blackstart unit material to and
designated as part of a transmission operator entity’s restoration plan, or;
III.c.4
Any generator, regardless of size, that is material to the reliability of the
bulk power system.
[Exclusions:
A generator owner/operator will not be registered based on these criteria
if responsibilities for compliance with approved NERC reliability
standards or associated requirements including reporting have been
transferred by written agreement to another entity that has registered for
the appropriate function for the transferred responsibilities, such as a
load-serving entity, G&T cooperative or joint action agency as described
in Sections 501 and 507 of the NERC Rules of Procedure.
As a general matter, a customer-owned or operated generator/generation
that serves all or part of retail load with electric energy on the customer’s
side of the retail meter may be excluded as a candidate for registration
based on these criteria if (i) the net capacity provided to the bulk power
system does not exceed the criteria above or the Regional Entity otherwise
determines the generator is not material to the bulk power system and (ii)
standby, back-up and maintenance power services are provided to the
generator or to the retail load pursuant to a binding obligation with
another generator owner/operator or under terms approved by the local
regulatory authority or the Federal Energy Regulatory Commission, as
applicable.
For purposes of applying these criteria, the Generator Interconnection
Facility is considered as though part of the generating facility. The
Generator Interconnection Facility is defined to be:
“ Sole-use facility for the purpose of connecting the generating unit(s) to
the transmission grid. In this regard, the sole-use facility only transmits
power associated with the interconnecting generator, whether delivered to
the grid or delivered to the generator for station service or auxiliary load,
or delivered to meet cogeneration load requirements.”]
III(d) Transmission Owner/Operator:
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
105
III.d.1
An entity that owns/operates an integrated transmission element associated
with the bulk power system 100 kV and above, or lower voltage as defined
by the Regional Entity necessary to provide for the reliable operation of
the interconnected transmission grid; or
III.d.2
An entity that owns/operates a transmission element below 100 kV
associated with a facility that is included on a critical facilities list that is
defined by the Regional Entity.
[Exclusion: A transmission owner/operator will not be registered based
on these criteria if responsibilities for compliance with approved NERC
reliability standards or associated requirements including reporting have
been transferred by written agreement to another entity that has registered
for the appropriate function for the transferred responsibilities, such as a
load-serving entity, G&T cooperative or joint action agency as described
in Sections 501 and 507 of the NERC Rules of Procedure.
In addition, a Generator Interconnection Facility as defined in Section
III.c.4 is not considered an integrated transmission element for purposes
of applying these criteria. ]
IV. Joint Registration Organization and applicable Member Registration.
Pursuant to FERC’s directive in paragraph 107 of Order No. 693, NERC’s rules
pertaining to joint registrations and Joint Registration Organizations are now found in
Section 501 and 507 of the NERC Rules of Procedure.
V.
If NERC or a Regional Entity encounters an organization that is not listed in the
compliance registry, but which should be subject to the reliability standards, NERC or the
Regional Entity is obligated and will add that organization to the registry, subject to that
organization’s right to challenge as provided in Section 500 of NERC’s Rules of Procedure
and as described in Note 3 below.
Notes to the above Criteria
1. The above are general criteria only. The Regional Entity considering registration of an
organization not meeting (e.g., smaller in size than) the criteria may propose registration
of that organization if the Regional Entity believes and can reasonably demonstrate 10 that
the organization is a bulk power system owner, or operates, or uses bulk power system
assets, and is material to the reliability of the bulk power system. Similarly, the Regional
Entity may exclude an organization that meets the criteria described above as a candidate
for registration if it believes and can reasonably demonstrate to NERC that the bulk
power system owner, operator, or user does not have a material impact on the reliability
of the bulk power system.
10
The reasonableness of any such demonstration will be subject to review and remand by NERC itself, or by any
agency having regulatory or statutory oversight of NERC as the ERO (e.g., FERC or appropriate Canadian
authorities).
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
106
2. An organization not identified using the criteria, but wishing to be registered, may
request that it be registered. For further information refer to: NERC Rules of Procedure,
Section 500 – Organization Registration and Certification; Part 1.3.
3. An organization may challenge its registration within the compliance registry. NERC or
the Regional Entity will provide the organization with all information necessary to timely
challenge that determination including notice of the deadline for contesting the
determination and the relevant procedures to be followed as described in the NERC Rules
of Procedure; Section 500 – Organization Registration and Certification.
4. If an entity is part of a class of entities excluded based on the criteria above as
individually being unlikely to have a material impact on the reliability of the bulk power
system, but that in aggregate have been demonstrated to have such an impact it may be
registered for applicable standards and requirements irrespective of other considerations.
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
107
Appendix 3 — Proposed Standards Authorization Request
and Redline Standard Revisions
Generator Requirements at the Transmission Interface Final Report
November 16, 2009
108
Standards Authorization Request Form
E-mail completed form to
maureen.long@nerc.net
Standard Authorization Request Form
Title of Proposed Standard
Requirements
Various Standards Containing GO/GOP and TO/TOP
Request Date
October 30, 2009November 16, 2009
SC Approval Date
SAR Requester Information
SAR Type (Check a box for each one
that applies.)
Name
Ad Hoc Group for Generator
Requirements at the Transmission Interface
New Standard
Primary Contact
Revision to existing Standard
Telephone
Scott Helyer
817-462-1512
Withdrawal of existing Standard
shelyer@tnsk.com
Urgent Action
Fax
E-mail
SAR–109
Standards Authorization Request Form
Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
The proposed changes to the requirements and the addition of new requirements will add
significant clarity to Generator Owners and Generator Operators regarding their reliability
standard obligations at the interface with the interconnected grid.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
Significant industry concern exists regarding the application of Transmission Owner and
Transmission Operator requirements, and more generally, to the registration of Generator
Owners and Generator Operators as Transmission Owners and Transmission Operators,
based on the facilities that connect the generators to the interconnected grid. The final
report of the Ad Hoc Group for Generator Requirements at the Transmission Interface
evaluated the issue and proposes a number of changes that adds much needed clarity on
the requirements for Generator Interconnection Facilities. Absent these revisions and
additional requirements, Generator Owners and Generator Operators are subject to what
some believe to be inappropriate registration as Transmission Owners and Transmission
Operators to ensure coverage for certain reliability requirements. The modifications and
additions recommended wholly and directly address the requirements for Generator Owners
and Generator Operators regarding its Generator Interconnection Facilities, and add
particular focus on the operation of the interface point at which operating responsibility
shifts from the GEnerator Operator to the Transmission Operator.
The proposal also modifies certain of NERC's existing gloassary terms and adds new terms
to support the standards modifications.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
32 NERC Reliability Standards contain language regarding generators or generating facilities
for which greater clarity regarding its Generator Interconnection Facilities would ensure no
reliability gap exists
12 requirements in FAC-003-1 - Transmission Vegetation Management should have their
applicability expanded to include Generator Owners.
2 NERC Reliability Standards should have their applicability expanded to include Generator
Operators to address general reliability gaps not attributable to their Generator
Interconnection Facilities.
8 new Reliability Standard Requirements should be added to ensure the responsibilities for
owning and operating the Generator Interconnection Facility are clear, and to address
certain requirements that should apply to all generators regardless of interconnection
configuration.
New NERC Glossary definitions are needed for Generator Interconnection Facility and
Generator Interconnection Operational Interface, as well as modifications to Vegetation
Inspection, Right-of-Way, Generator Owner, Generator Operator, and Transmission
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
Refer to Final Report of the Ad hoc Group for Generator Requirements at the Transmission
Interface.
SAR–110
Standards Authorization Request Form
Revisions to the latest versions of the following standards are included in the report and
redline standard changes are included to accompany this SAR:
BAL-005
CIP-002
EOP-001, -003, -004, -008
FAC-001, -003, -008, -009
IRO-005
MOD-010, -012
PER-001, -002
PRC-001, -004, -005
TOP-001, -002, -003, -004, -008
VAR-001, -002
SAR–111
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer
Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.
LoadServing
Entity
Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.
SAR–112
Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market
Interface Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR–113
Standards Authorization Request Form
Related Standards
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR–114
Unofficial Comment Form for Generator Requirements at the Transmission
Interface — Project 2010-07
Please DO NOT use this form to submit comments. Please use the electronic form located
at the link below to submit comments on the proposed SAR and modifications to several
reliability standards and NERC Glossary terms associated with the recommendations of the
Generator Requirements at the Transmission Interface Ad Hoc Group, embodied in Project
2010-07. Comments must be submitted by March 15, 2010. If you have questions please
contact David Taylor at david.taylor@nerc.net or by telephone at (609) 651-5089.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Background Information:
On January 14, 2008, the NERC Board of Trustees Compliance Committee rendered a
decision upholding the Western Electricity Coordinating Council’s (WECC’s) determination to
register the New Harquahala Generating Company (“Harquahala”) as a Transmission Owner
and Transmission Operator. This determination is based on Harquahala’s 26-mile 500 kV
interconnection facilities that connect the plant with the Hassayampa transmission
substation. This decision was upheld by FERC and caused concern for generator owners and
generator operators who owned only transmission “tie-line” facilities used to connect their
generating facilities to a transmission substation.
In response to concerns from members of the generator segment regarding this decision,
NERC undertook a survey in the Fall of 2008 to clearly define stakeholders concerns; to
review and highlight those transmission owner and transmission operator requirements that
should be considered for generic applicability for generator owners and generator operators
for their tie-line facilities; and to collect ideas for resolving the generator owner and
generator operator concerns.
There were wide-ranging viewpoints to the topic from the over 100 respondents but there
was no support for merely assigning all transmission owner and transmission operator
requirements to the generator owner and generator operator solely on the basis of owning
interconnection facilities. One consistent suggestion was to assemble a group of industry
representatives to analyze and make recommendations for resolving the concerns, thereby
establishing general criteria for determining whether generator owners and generator
operators should be registered for transmission owner and transmission operator
requirements in NERC’s reliability standards.
Accordingly, in February, 2009, NERC announced the formation of the Ad Hoc Group for
Generator Requirements at the Transmission Interface. Its objective was to:
“Evaluate existing NERC Reliability Standard requirements and develop a
recommendation and possible standards authorization request to address gaps in
reliability for interconnection facilities of the Generator Owner and expectations for
the Generator Operator in operating those facilities. Propose strategies to address or
resolve other related issues as appropriate.”
In November, 2009, the group published its final report that included the following
conclusions and recommendations:
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Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
Conclusions
1. Generator Interconnection Facilities operating at a voltage of 100 kV or greater or
those deemed critical to the Bulk Electric System by the Regional Entity makes the
Generator Interconnection Facility part of the Bulk Electric System for purposes of
applying Generator Owner and Generator Operator requirements but not for applying
Transmission Owner or Transmission Operator requirements.
2. The Generator Owner or Generator Operator that owns and/or operates a Generator
Interconnection Facility, that is, a sole-use facility that interconnects the generator to
the grid, should not be registered as a Transmission Owner or Transmission Operator
by virtue of owning or operating its Generator Interconnection Facility.
3. A Generator Interconnection Facility is considered as though part of the generating
facility specifically for purposes of applying Reliability Standards to a Generator
Owner or Generator Operator.
4. Changes to NERC Reliability Standards are needed to ensure complete reliability
coverage of the Generator Interconnection Facility.
a. 32 NERC Reliability Standard requirements contain language regarding
generators or generating facilities for which greater clarity regarding its
Generator Interconnection Facilities would ensure that no reliability gap
exists.
b. 12 requirements in FAC-003-1 – Transmission Vegetation Management should
have their applicability expanded to include Generator Owners.
c. 2 NERC Reliability Standards should have their applicability expanded to
include Generator Operators to address general reliability gaps not
attributable to the Generator Interconnection Facility.
d. 8 new Reliability Standard requirements should be added to ensure the
responsibilities for owning and operating the Generator Interconnection
Facility are clear, and to address certain requirements that should apply to all
generators regardless of interconnection configuration.
5. If a generator is connected to multiple transmission facilities that are subject to
network power flows (that is, power flow on these multiple transmission facilities
includes power not solely associated with the generator output, requirements for
station service, auxiliary load, or cogeneration load), then those transmission
facilities are integrated transmission facilities and should be subjected to the
applicable Transmission Owner and Transmission Operator Standard
Requirements1 1.
6. After review of the existing Transmission Owner requirements that are not currently
applicable to Generator Owners, only FAC-003-1 should have its applicability
expanded to include Generator Owners as a result of the Generator Interconnection
Facility, if the length of the Generator Interconnection Facility exceeds two spans
(generally, more than one-half mile) from the generator property line.
7. After review of the existing Transmission Operator requirements that are not
currently applicable to Generator Operators, no existing Transmission Operator
requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility.
1
1 A double-circuit line behind the point of interconnection, for example, that is carrying power solely associated
with the generation output, requirements for station service, auxiliary load, or cogeneration load, would not be
considered an integrated transmission facility by comparison.
7
Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
8. New NERC Glossary definitions are needed for Generator Interconnection Facility and
Generator Interconnection Operational Interface, as well as modifications to the
terms Vegetation Inspection, Right-of-Way, Generator Owner, Generator Operator,
and Transmission.
Recommendations
1. Submit Standards Authorization Requests (SARs) requesting expeditious action to
add or modify the definitions in NERC’s Glossary for Generator Interconnection
Facility and Generator Interconnection Operational Interface, as well as modifications
to the terms Vegetation Inspection, Right-of-Way, Generator Owner, Generator
Operator, and Transmission.
2. Submit SARs requesting expeditious action to modify existing standard requirements
to add specificity for Generator Interconnection Facility where appropriate, to add
Generator Operator applicability where needed, to add requirements to capture
responsibilities for owning and operating the Generator Interconnection Facility, and
to add requirements where necessary that should be applicable to Generator
Operators regardless of the interconnection configuration.
3. Modify the applicability of FAC-003-1 to apply to Generator Owners when their
Generator Interconnection Facility operates at 200 kV or above and exceeds two
spans from the generator property line, or otherwise is deemed to be critical to the
Bulk Electric System.
4. Modify the NERC Rules of Procedure, NERC Compliance Registry Criteria, and other
documents as necessary to reflect that a Generator Owner should not be registered
as a Transmission Owner and a Generator Operator should not be registered as a
Transmission Operator on the basis of the Generator Interconnection Facility.
5. NERC and the Regional Entities should refrain from further registering Generator
Owners and Generator Operators as Transmission Owners and Transmission
Operators generically by virtue of the Generator Interconnection Facility.
6. Based on the conclusions and recommendations offered in this report, NERC and the
Regional Entities should carefully develop and implement a plan to address deregistering those Generator Owners and Generator Operators that have previously
been registered as a Transmission Owner and Transmission Operator by virtue of the
Generator Interconnection Facility.
The complete final report is located at the following link:
http://www.nerc.com/files/GO-TO_Final_Report_Complete_2009Nov16.pdf
Specifically, the following new or revised terms are being proposed for the NERC Glossary
and are presented for consideration:
Transmission
An interconnected group of lines and associated equipment for the movement or transfer of
electric energy between points of supply and points at which it is transformed for delivery to
customers or is delivered to other electric systems. Generator Interconnection Facility is not
included in this definition.
Generator Owner
Entity that owns and maintains generating units, including its Generator Interconnection Facility.
Generator Operator
7
Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
The entity that operates generating unit(s) and the Generator Interconnection Facility and
performs the functions of supplying energy and Interconnected Operations Services. The
Generator Operator also operates the Generator Interconnection Facility and is responsible
for coordinating with the Transmission Operator when the facility is energized or about to be
energized to/de-energized from the transmission system.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The Transmission Owner owner of
the electric lines may own the land in fee, own an easement, or have certain franchise,
prescription, or license rights to construct and maintain lines.
Vegetation Inspection
The systematic examination of a transmission corridor Transmission Line or Generator
Interconnection Facility Right-of-Way to document vegetation conditions.
Generator Interconnection Facility (NEW)
Sole-use facility for the purpose of connecting the generating unit(s) to the transmission
grid. In this regard, the sole-use facility only transmits power associated with the
interconnecting generator, whether delivered to the grid or delivered to the generator for
station service or auxiliary load, or delivered to meet cogeneration load requirements.
Generator Interconnection Operational Interface (NEW)
Location at which operating responsibility for the Generator Interconnection Facility changes
between the Transmission Operator and the Generator Operator.
In addition, the following new requirements are being proposed for inclusion in the
Reliability Standards and are included in the respective standards located in Appendix 1 of
the final report:
1. The Generator Operator who has responsibility for monitoring the status of a special
protection system or remedial action scheme at the generating facility for the benefit
of Bulk Electric System reliability should notify the Transmission Operator when a
change in status or capability occurs. (IRO-005)
2. Each Generator Operator shall provide its operating personnel with the responsibility
and authority to implement real-time actions to ensure the stable and reliable
operation of the Generation Facility and the Generation Interconnection Facility, and
to implement directives of the Transmission Operator and Balancing Authority. (PER001)
3. Each Generator Operator shall implement an initial and continuing training program
for all personnel responsible for operating the Generator Interconnection Facility to
ensure the ability to operate the equipment in a reliable manner. (Per-002)
4. The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects to
preserve Interconnection reliability. (TOP-001)
5. The Transmission Operator has decision-making authority for the Generator
Interconnection Operational Interface. (TOP-001)
6. The Generator Operator shall notify the Transmission Operator of a change in status
of the Generation Interconnection Facility.
7. The Generator Operator shall operate the Generation Interconnection Facility within
Facility Ratings. (TOP-004)
7
Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
8. The Generator Operator shall disconnect the Generation Interconnection Facility
immediately in coordination with the Transmission Operator when time permits or as
soon as practical thereafter if an overload or other abnormal condition threatens
equipment or personnel safety. (TOP-008)
Finally, Appendix 1 of the final report contains the table of reliability standards reviewed by
the ad hoc group pertaining to Generator Owner, Generator Operator, Transmission Owner,
and Transmission Operator and the recommended revisions proposed by the ad hoc team
therein.
The ad hoc team believes that these modifications to the definitions and requirements,
coupled with the proposed revisions to the compliance registration criteria that are identified
in the GO-TO Final Report, will result in closing the reliability gap that previously existed
where it wasn’t clear what entity had responsibility for requirements associated with the
facilities that connect generating plants to transmission substations, without placing an
undue burden on Generator Owners and Generator Operators.
1. Do you agree that there is a reliability-related need for the proposed standards action?
Yes
No
Comments:
2. Do you agree with the scope of the proposed standards action?
Yes
No
Comments:
3. Do you agree with the proposed NERC Glossary additions or revisions? If you disagree
with one or more of the proposed new or modified definitions, please provide a revision
that would make the definition acceptable to you.
Yes
No
Comments:
4. Do you agree with the proposed new requirements intended to add clarity around
expectations for generator owners and operators at the transmission interface?
Yes
No
Comments:
5. Do you agree with the proposed modified requirements intended to add clarity around
expectations for generator owners and operators at the transmission interface?
Yes
No
7
Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
Comments:
6. Do you believe there are any other Transmission Owner or Transmission Operator
standards or requirements that should be applicable to the Generator Owner or
Generator Operator other than those identified?
Yes
No
Comments:
7. The next posting of the proposed revisions to these standards will include conforming
changes to the measures and compliance elements, and will include an implementation
plan. Please identify how much time you feel an entity will need to become fully
compliant with the following new/revised requirements:
The Generator Operator who has responsibility for monitoring the status of a special
protection system or remedial action scheme at the generating facility for the benefit
of Bulk Electric System reliability should notify the Transmission Operator when a
change in status or capability occurs. (IRO-005)
Time needed to become fully compliant:
Comments:
a. Each Generator Operator shall provide its operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and
reliable operation of the Generation Facility and the Generation Interconnection
Facility, and to implement directives of the Transmission Operator and Balancing
Authority. (PER-001)
Time needed to become fully compliant:
Comments:
b. Each Generator Operator shall implement an initial and continuing training
program for all personnel responsible for operating the Generator Interconnection
Facility to ensure the ability to operate the equipment in a reliable manner. (Per002)
Time needed to become fully compliant:
Comments:
c. The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects to
preserve Interconnection reliability. (TOP-001)
Time needed to become fully compliant:
Comments:
d. The Transmission Operator has decision-making authority for the Generator
Interconnection Operational Interface. (TOP-001)
Time needed to become fully compliant:
Comments:
7
Unofficial Comment Form — SAR and Proposed Revisions to Standards and Definitions for
Project 2010-07
e. The Generator Operator shall notify the Transmission Operator of a change in
status of the Generation Interconnection Facility.
Time needed to become fully compliant:
Comments:
f. The Generator Operator shall operate the Generation Interconnection Facility
within Facility Ratings. (TOP-004)
Time needed to become fully compliant:
Comments:
g. The Generator Operator shall disconnect the Generation Interconnection Facility
immediately in coordination with the Transmission Operator when time permits or as
soon as practical thereafter if an overload or other abnormal condition threatens
equipment or personnel safety. (TOP-008)
Time needed to become fully compliant:
Comments:
8. If you have any other comments on this SAR or proposed standard revisions and NERC
Glossary modifications that you have not already provided in response to the prior
questions, please provide them here.
Comments:
7
Standards Announcement
Standards Authorization Request (SAR) Comment and Drafting Team
Nomination Periods Open
Project 2010-07: Generator Requirements at the Transmission Interface
Now available at: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Nominations for Drafting Team (through March 1, 2010)
The Standards Committee is seeking industry experts to serve on the Generator Requirements at the
Transmission Interface Drafting Team (see project background below).
If you are interested in serving on this drafting team, please complete this electronic nomination form by
March 1, 2010.
Comment Period (through March 15, 2010)
The Standards Committee has posted a proposed SAR for a 30-day comment period ending on March 15,
2010. Also posted are proposed revisions to existing standards and a copy of the final report published by the
Ad Hoc Group for Generator Requirements at the Transmission Interface.
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at Lauren.Koller@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page (see project background below).
Project Background
On January 14, 2008, the NERC Board of Trustees Compliance Committee upheld the Western Electricity
Coordinating Council’s (WECC’s) determination to register the New Harquahala Generating Company
(Harquahala) as a Transmission Owner and Transmission Operator. This determination is based on
Harquahala’s 26-mile 500 kV interconnection facilities that connect the plant with the Hassayampa
transmission substation. This decision was upheld by FERC and caused concern for Generator Owners and
Generator Operators who owned only transmission “tie-line” facilities used to connect their generating facilities
to a transmission substation.
In response to concerns from members of the generator segment regarding this decision, NERC conducted a
survey in the Fall of 2008 to define and collect recommendations for resolving stakeholders concerns, and to
review and highlight those Transmission Owner and Transmission Operator requirements that should be
considered for generic applicability for Generator Owners and Generator Operators for their tie-line facilities.
Based on the survey recommendations, NERC formed a group of industry representatives to “Evaluate existing
NERC Reliability Standard requirements and develop a recommendation and possible standards authorization
request to address gaps in reliability for interconnection facilities of the Generator Owner and expectations for
the Generator Operator in operating those facilities. Propose strategies to address or resolve other related issues
as appropriate.” In November 2009, the group published report of its conclusions and recommendations.
This project is the result of those recommendations, which include proposed definitions and changes to existing
standards to add clarity to Generator Owners and Generator Operators regarding their reliability standard
obligations at the interface with the interconnected grid.
Project page: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at shaun.streeter@nerc.net or at 609.452.8060.
Checkbox® 4.4
Newsroom Site Map Contact NERC
Individual or group. (41 Responses)
Name (26 Responses)
Organization (26 Responses)
Group Name (15 Responses)
Lead Contact (15 Responses)
Question 1 (39 Responses)
Question 1 Comments (41 Responses)
Question 2 (36 Responses)
Question 2 Comments (41 Responses)
Question 3 (32 Responses)
Question 3 Comments (41 Responses)
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Question 4 Comments (41 Responses)
Question 5 (34 Responses)
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Question 6 (35 Responses)
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Question 7 (0 Responses)
Question 7 Time needed to become fully compliant (41 Responses)
Question 7 Comments (41 Responses)
Question 7a (0 Responses)
Question 7a Time needed to become fully compliant (41 Responses)
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Question 7b Time needed to become fully compliant (41 Responses)
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Question 7d Time needed to become fully compliant (41 Responses)
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Question 7e Time needed to become fully compliant (41 Responses)
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Question 7f Time needed to become fully compliant (41 Responses)
Question 7f Comments (41 Responses)
Question 7g (0 Responses)
Question 7g Time needed to become fully compliant (41 Responses)
Question 7g Comments (41 Responses)
Question 8 (0 Responses)
Question 8 Comments (41 Responses)
Individual
Larry Rodriguez
Entegra Power Group LLC
Yes
But, that action should be reasonable, provide specific detail, and be kept simple so the
reliability-related objectives are effectively understood by those operators of the GI Facilities.
Yes
BUT, FAC-003 SHOULD BE APPLIED IN A REASONABLE MANNER. MORE DETAIL SHOULD BE
PROVIDED THAN IT WOULD APPLY FOR MORE THAN 2 SPANS. WHAT IF THERE ARE 3 SPANS,
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BUT ONLY A QUARTER MILE IN DISTANCE WHICH IS TOTALLY VISIBLE FROM THE GIF. THE SDT
SHOULD MAKE SOME REASONABLE CONCESSIONS FOR THESE SITUATIONS, OR ALLOW THE GIF
TO DOCUMENT THE SOUND REASONING USED IN NOT IMPLEMENTING FAC-003 TO THE EXTENT
REQUIRED BY THE EXISTING STANDARD. A REASONABLE VEGETATION MANAGEMENT PROGRAM
SHOULD BE ADEQUATE. MORE DETAIL AND SPECIFICS DESCRIBING WHAT ADEQUATE
TRAINING IS FOR PER-002.
Yes
Yes
SEE COMMENTS FOR QUESTION 2.
Yes
SEE COMMENTS FOR QUESTION 2.
No
NO COMMENT
NO COMMENT
1 YEAR
NO COMMENT
NO COMMENT
NO COMMENT
NO COMMENT
NO COMMENT
Individual
Ken Parker
Entegra Power Group LLC, i.e., Gila River Power and Union Power Partners
Yes
Yes
Yes
Yes
Yes
No
18 months
12 months
12 months
12 months
12 months
8 months
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6 months
12 months
FAC-003 - Applicability apply to GIF above 200 kV that exceed two spans should be revised to
"less than one-half mile" as span lengths vary considerably. For example we have 3 spans over
1/4 mile. R1. requirement to "keep current, a formal TVMP" should allow latitude for those
entities with one-quarter mile of radial connecting transmission, all visible from the office
window, to have a less than a formal program, or at least a very SIMPLE program.
Individual
Jack Stamper
Public Utility District #1 of Clark County
Yes
No
Clark Public Utilities believes the scope of the proposed standards actions is too broad.
No
Clark Public Utilities believes the proposed definitions do not provide the necessary amount of
guidance and clarity. The proposed definitions and standards revisions are being considered
because of the potential impacts of a 26-mile 500 kV Generation Interconnection Facility. The
proposed definition for the term “Generation Interconnection Facility†will include the 26mile interconnection as well as a host of other types of interconnections that should not be
considered in this effort. Clark’s generator is attached to the transmission grid by slack span
(less than 100’) between the high side of the GSU (owned by the generator)and a circuit
breaker (owned and operated by the Transmission Operator) located within the Transmission
Operators switchstation. There are no operable components in the slack span. Clark believes the
currently proposed standards actions are overly broad. The definitions and applicability of these
standards must be narrowed. Clark proposes the following definition for Generator
Interconnection Facility. Generator Interconnection Facility Sole-use facility for the purpose of
connecting the generating unit(s) to the transmission grid In this regard, the sole-use facility
only transmits power associated with the interconnecting generator, whether delivered to the
grid or delivered to the generator for station service or auxiliary load, or delivered to meet
cogeneration load requirements. Generator Interconnection Facilities shall not include lines that
are less than or equal to two spans in length or lines that the host Transmission Operator has
agreed to include as part of the transmission system it operates.
No
Many of the new requirements place excessive demands on generators that do not increase
system reliability. In EOP-003 Generator Operators are added to the applicability and as a result
R7 is a newly applicable requirement to Generator Operators. However, this requirement now
implies that Generator Operators are required to engage in the coordination efforts (with the BA
and TOP) of automatic underfrequency load shedding. Generators do not have the option of
determining what levels of frequency to ride through and what levels of frequency to trip on.
Those quantities are defined by the RC and the BA and Generator Operators are required to have
generator protection system settings that allow this ride through. Generators should have
frequency and voltage ride through requirements that are coordinated with automatic load
shedding programs by the RC, BA and/or TOP but should simply be required to comply with
these requirements and shoud not have a role in the coordination. The comments in the GOTO
Final report indicate that this addition is required to ensure that a generator frequency trip set
point is appropriately included in the currently required coordination between the BA and TOP.
Clark believes that generators should not participate in the coordination but simply be required
to comply with frequency ride through requirements dictated by the RC, BA and/or TOP. Clark
believes that FAC-002 clearly applies to Generator Owners and this standard requires that
generator integration facilities address reliability impacts in the interconnected transmission
system. Additionally, the proposed change to EOP-003 appears to have nothing to do with the
issue at hand (i.e. removal of TOP status to a generator because of a Generator Interconnection
Facility). Clark believes it is inappropriate to make EOP-003 applicable to Generator Operators
and to imply that a Generator Operator has any participation in coordination of underfrequency
load shedding other than to comply with frequency ride through requirements of the RC, BA
and/or TOP. Clark agrees that the changes to FAC-003 are appropriate, will lead to increased
reliability and do not result in unnecessary reporting or paperwork. The applicability section
clearly limits the scope of what Generation Interconnection Facilities would be included in this
standard by having a “two span†limit in the length of the facility. This limit appropriately
will exclude those generators that have arranged for a Transmission switchstation owned and
operated by a Transmission Operator located immediately adjacent to the generator. In IRO005, R13, the standard proposes to require a Generator Operator to immediately inform the TOP
of status changes to SPS. While Clark is not opposed to this change, it is unclear why the issue
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at hand (i.e. removal of TOP status to a generator because of a Generator Interconnection
Facility) has lead to this addition. The SAR implies that the industry need leading to the SAR is
the “registration of Generator Owners and Generator Operators as Transmission Owners and
Transmission Operators, based on the facilities that connect the generators to the interconnected
grid.†IRO-005, R13 does not appear to have any connection to this industry need. In PER-001,
Generator Operators are added to the applicability and as a result of the new R2 Generator
Operators will be required to demonstrate the authority of operating personnel over Generation
Facilities and Generation Interconnection Facilities. This level of authority is unnecessary.
Transmission Operators already have this authority (refer to PER-001, R1). Generator Operators
are already required to comply with reliability directives issued by RCs, BAs, and TOPs in other
reliability standards. The requirement to demonstrate that a generator needs this authority over
its generating facility is unnecessary and has no connection with the industry need the SAR is
based on. A generator operator has authority over its generator by virtue of its registration as a
Generator Operator. The need for further proof that a GOP can operate generation facilities for
which it is a registered GOP has not been demonstrated. The requirement to demonstrate that a
generator needs authority over a Generation Interconnection Facility is; for the same reason,
unnecessary. A generator operator has authority over its generator by virtue of its registration as
a Generator Operator for that facility. The need for further proof that a GOP can operate
Generation Interconnection Facilities for which it is a registered GOP has not been demonstrated.
In PER-002, Generator Operators are added to the applicability and as a result of the new R3
Generator Operators will be required to demonstrate training programs similar to TOP training
requirements. Clark is not opposed to training its GOP personnel; however, including the training
program within the PER-002 training requirements elevates this training to a level that has not
been demonstrated to be necessary in all cases. Currently, this requirement is applicable to a
TOP. By removing the TOP classification to certain GO/GOP registered entities that are only a
TOP by virtue of Generation Interconnection Facilities, the potential exists that inadequately
trained personnel may be directing the operation of a Generation Interconnection Facility.
However, as stated earlier, when the Generation Interconnection Facility is short in length and
more importantly when this facility has no devices which can be operated (i.e. direct connection
between the generator step-up transformer or generator protection circuit breaker (owned or
operated by the GOP) and the TOP owned and operated transmission breaker) there is no gap in
having adequately trained personnel operating transmission facilities. Clark believes the
applicability section should include minimal limits for applicable Generation Interconnection
Facilities or that the definition of Generation Interconnection Facilities should be amended such
that PER-002 applicability is limited to GOPs that own facilities that are similar in nature to the
New Harquahala Generation Interconnection Facilities that have led to this SAR. The proposed
changes to TOP-004 are confusing. The proposal does not add GOP in the applicability section
but the newly proposed R7 appears to obligate GOPs. The requirement should be revised to
obligate a TOP to ensure that a GOP operates within its applicable limits. These limits should
have already been established. In FAC-008 Transmission Owners and Generator Owners are
required to have a ratings methodology. In FAC-009 TOs and GOs are required to calculate
facility ratings. In both of these standards, documentation is to be made available to RCs, TOPs,
PAs and TPs that have responsibility. At the very least, the applicability section of a standard
should be coordinated with the entities having obligations due to the requirements of a standard.
Yes
Except as discussed in comments 2, 3, and 4, Clark is in agreement with the proposed changes.
No
No time
Clark has no SPS or RAS for which it is responsible.
No Time.
Clark’s Generator Operator personnel have responsibility and authority to implement realtime actions to ensure the stable and reliable operation of the Generation Facility and the
Generation Interconnection Facility, and to implement directives of the Transmission Operator
and Balancing Authority.
Twelve months.
Clark’s generating operating personnel regularly engage in training however, to implement a
Training Program as rigorous as the TOP Training Program will take some time to complete.
No Time.
Clark believes the operation of its generator is already under the direction of its TOP and that
coordination has already occurred since the TOP has included the operation of Clark’s
generator in its TOP-002 Normal Operations Plan.
No time.
Clark believes that existing standards already grant the TOP decision-making authority for the
Generator Interconnection Operational Interface.
No time.
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Clark’s Generation Interconnection Facility status is already provided to the TOP in real time
over the TOP’s SCADA system.
No time.
The Generation Interconnection Facilities of Clark have ratings that exceed the maximum
generating capability of the interconnected generation facility.
No time.
Clark has experienced no operating conditions where it had to disconnect the Generation
Interconnection Facility immediately due to an overload or other abnormal condition that
threatened equipment or personnel safety.
Individual
Daniel E. Kujala
Detroit Edison Company
No
Vegetation Inspection change to include any BES component Transmission Line or Generator
Interconnection Facility Right-of-Way or any other BES component to document vegetation
conditions .
Yes
Yes
Yes
No
Individual
Mark Bennett
Competitive Power Ventures, Inc.
Yes
In fact, the technical analysis in the Ad Hoc Group's Report provides a valuable and useful
understanding of the specific nature and extent of reliability issues associated with generator
interconnection facilities. Up to now, the need for generator TO/TOP registrations has not been
supported by a clear and technically sound rationale. The Report's conclusion, based upon its
comprehensive and thorough review, that there is no need for generators to be registered as
TO/TOPs to address the specific reliability issues is especially significant.
Yes
Yes
Yes
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No
Every effort should be made to precisely describe requirements that directly correspond to, and
address, the reliability issues framed by the GO/TO Ad Hoc Group. Particularly, "interconnection
facilities" should be defined to account for and exclude various transmission configurations on the
generator side of the interconnection point that do not create network power flows or otherwise
operate as bona fide transmission systems.
Group
SERC Planning Standards Subcommittee
Philip R. Kleckley
Yes
Yes
No
We suggest 3 alternate modified definitions: Right-of-Way (ROW) A corridor of land on which a
Transmission Line or Generator Interconnection Facility may be located. The owner of the
Transmission Line or Generator Interconnection Facility may own the land in fee, own an
easement, or have certain franchise, prescription, or license rights to construct and maintain
lines. Vegetation Inspection The systematic examination of a Right-of-Way to document
vegetation conditions. The main reason for the change in definition for ROW was the proposed
use of the non-capitalized term "electric line". Since the use of that phrase sometimes means
distribution lines as well as transmission, we suggest staying with the capitalized NERC terms for
better clarity. Generator Operator The entity that operates generating unit(s) and performs the
functions of supplying energy and Interconnected Operations Services. The Generator Operator
may also operate the Generator Interconnection Facility. The main reason for the change in the
definition for Generator Operator was that the 2nd sentence in the proposed definition was a
requirement and not a true definition. The other change was to allow for the case where the
Generator Operator was not the operator of the Generator Interconnection Facility.
Yes
Yes
No
12 months
12 months
12 months
12 months
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12 months
12 months
12 months
12 months
No other comments
Group
Northeast Power Coordinating Council
Guy Zito
The term “two spans†is used in the Introductory Section of this Comment Form
(Conclusions Item 6, Recommendations Item 3), and will need a clear, and specific definition. â
€œGenerally†is not a word to be used in a definition.
Individual
Sam Dwyer
AmerenUE, Power Operations Services
Yes
No
While we agree with the overall scope of the proposed actions, there appears to be one missing
critical element. What requirement will ensure that each GO, GOP, TO and TOP agree on the
specifics of implementing these new requirements for each GIF? Has the Ad Hoc Group
considered adding a requirement to mandate execution of an Agreement or Procedure between
the GO, GOP, TO and TOP to ensure minimal specific actions that would guarantee compliance
with each GIF Requirement?
Yes
No
See response to Item #2.
No
See response to Item #2.
No
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The items in Question #7 illustrate the need for a written Agreement or Procedure between the
GO, GOP, TO and TOP on how to comply with these new, and modified, Requirements. An
Agreement or Procedure would provide the certainty of: • Assignable and measurable
responsibilities, • Mutual agreement on specific actions, and • Implementation deadlines.
Without such an Agreement or Procedure, there will be no auditable commitment to defined
specific actions, predetermined responsibilities and closure of the reliability gap in total.
Group
Luminant
Rick Terrill
No
In general, Luminant agrees there is a need to address generation facilities with extended
connections to the transmission system. However, Luminant does not agree there is a reliability
need for the proposed standards action as it relates to generators connected in close proximity
to the grid where the connection typically consists of a bus or short wires connection from the
high side of a generator step up transformer to the generator breaker.
No
: Luminant believes the scope of the standards action significantly exceeds the reliability need.
The scope should only extend to Generation Interconnection Facilities of greater than one-half
(½) mile in length from the property boundary of the generation plant. This standards action
should only be applied where there is a demonstrated reliability benefit. For the bulk of the
Generator Owners, the proposal creates excessive documentation and paperwork, and increases
compliance risk with no reliability benefit to the Bulk Electric System (BES).
No
No, for the bulk of the Generator Owners whose Generation Interconnection Facilities (GIF) are
connected in close proximity (i.e., one-half mile or less) to the BES, the requirements will only
add additional unduly burdensome documentation, paperwork and compliance risk, with no
reliability benefit
No
The following comments are specific to each standard CIP-002 – This standard is currently
under revision and any change should be addressed by the Cyber Security Standards Revision
Team. EOP-003 – Application of this reliability standard to a GOP is incorrect. The Generator
Operator has no direct responsibility for load shedding. Only the TOP and BA have load shedding
responsibility. EOP-004 – The inclusion of GIF in this reliability standard is redundant as the
GOP has responsibility for all of its facilities, including any generators. . Since generation units
are not independently identified with a particular GOP, the GIF does not need to be
independently identified. Also, there is a NERC project currently underway to revise this standard
(Project 2009-01). FAC-003 – Luminant agrees this standard should apply in those instances
when the generator is connected to the BES through its GIF over a substantial distance.
However, the applicability of this standard to a GIF needs to specify a distance (such as one-half
(½) mile from the plant property boundary) not a number of spans since the spacing between
spans can vary from extensively. Defining the applicability of this standard in terms of a number
of spans will create inconsistency in the application of the requirements. IRO-005 – New
requirement R13 presumes that a Special Protection System (SPS) is the sole responsibility of a
GOP, which, in most cases, it is not. Most SPS are the responsibility of the TO, not the GOP. This
requirement does not define which SPS is being monitored. A requirement of this nature should
define an SPS on the GIF. PER-001 – The addition of a requirement applicable to GOP in this
standard goes well beyond the scope of this project’s purpose. A NERC Standards Drafting
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Team, under Project 2006-01, did not add any GOP requirements to the PER standards. This
proposed GOP requirement is redundant. Current NERC Reliability Standard TOP-001, R3
requires Generator Operators to follow reliability directives, as does IRO-001, R8. This proposed
requirement should be deleted. It adds paperwork, documentation and compliance risk with no
reliability benefit. The PER-001 standards were intended for overall grid management, not the
operation of a power plant. PER-002 – The recent NERC Standards Drafting Team, under
Project 2006-01, specifically declined to make this standard applicable to GOP. In addition, the
2006-01 project is retiring this standard with the adoption of the revised PER-005. PRC-001 –
The inclusion of Generator Interconnection Facility is redundant. However, there is a current
NERC Drafting team revising PRC-001 and this issue should be referred to that team. PRC-005 â
€“ Any revisions to PRC-005 should be referred to the current PRC-005 drafting team. TOP-001
– Draft Requirements R9 and R10 are extremely broad. These should only apply to narrowly
defined GIFs such as long span connections or GIFs with transmission load flowing through the
GIF. Care should be taken in this requirement not to duplicate requirements such as coordination
of outage planning. The requirements should be specific, and not fill in the blank for the TOP or
region. TOP-004 – Draft Requirement R7 is redundant to requirements in other standards and
is not needed. IR0-005-2, R13, and IRO-005-3, R10, require the GOP to operate the BES to its
most limiting factor, which is, by definition, implicitly within its facility ratings. TOP-008 – Does
draft requirement R5 fit in this standard that addresses IROL and SOL? This requirement should
only apply to the same long connection GIF facilities identified in TOP-003.
No
18 months
18 months
24 months
18 months
18 months
18 months
18 months
36 months
Individual
Amir Hammad
Constellation Power Source Generation Inc.
Yes
Yes - Defining the compliance responsibility to align more accurately with operational reality is
important in managing reliability. However, the SDT must also consider those entities that enter
into a Joint Registration Organization (“JROâ€) for certain GOP reliability standards. This
registration exception applies to market entities, where there has been a JRO created that
delineates specific joint responsibilities, with respect to the GOP reliability standards. It is
incumbent on both parties to comply with their agreed upon respective responsibility.
No
Please see the comments for Question #4
No
The term “point of interconnection†must be used in the glossary definitions of a â
€œGenerator Interconnection Facility†and “Generator Interconnection Operational
Interface.†It is a common industry term that is widely understood, and is even being used in
the revision to FAC-008. Using the term “point of interconnection†would further clarify the
new glossary definitions. Here are the proposed changes: Generator Interconnection Facility
(NEW) Sole-use facility for the purpose of connecting the generating unit(s) to the transmission
grid. In this regard, the sole-use facility only transmits power associated with the interconnecting
generator, whether delivered to the grid or delivered to the generator for station service or
auxiliary load, or delivered to meet cogeneration load requirements.The Generator
Interconnection Facility is physically defined as the facility and its encompassing equipment
beginning at the low side of the Generator Step Up to the point of interconnection. Generators
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connected to the same interconnection facility with different Generator Operators must
coordinate operations. Generator Interconnection Operational Interface (NEW) Location at which
operating responsibility for the Generator Interconnection Facility changes between the
Transmission Operator and the Generator Operator.This location is known as the point of
interconnection.
Yes
Constellation agrees with the proposed new requirements in principal. However, further clarity is
needed in the requirements so that there isn’t any added confusion. Either an implementation
plan or a “frequently asked questions†document would be recommended.
No
Constellation agrees with the proposed changes for BAL-5, EOP-1, EOP-4, EOP-8, FAC-1, FAC-8,
FAC-9, IRO-5, MOD-10, MOD-12, PER-1, PRC-1, PRC-5, TOP-1, TOP-2, TOP-3, VAR-1, and VAR2. Furthermore, the changes made to CIP-2 are especially valuable in that the clarity it brings
with the added terminology would assist in identifying individual assets. Constellation does not
agree with (or has comments for) the proposed changes to: •EOP-3 – GOs/GOPs should not
be included in this standard •FAC-3 – Constellation agrees in principal with this change, but
further work is needed in regards to which GOs fall into this category. The wording may be
changed to “two or more spans exceeding ½ mile in total length,†but further discussions is
needed on this topic. •PER-2 – Constellation agrees in principal with this change, but
believes that this requirement should be combined into PRC-001 R1, and eliminate the
redundancy. •PRC-5 – Testing of the Protection System of the Generator Interconnection
Facility is not always the sole responsibility of the GO. Some verbiage attesting to that is needed.
Otherwise, it is wise to include the Generator Interconnection Facility into this standard so that
no gap may exist in the testing of a Protection System that may impact the BES.
No
1 year
2 years
Time is needed for training and terminology to percolate throughout the Generation Facility and
that it be ingrained with the Operators.
2 years
Time is needed to implement a training plan and revise it based on feedback from those being
trained.
1 year
1 year
1 year
1 year
1 year
Constellation would like to thank the Ad-Hoc group for the excellent work they did in creating the
GOTO Final Report. In particular, here are a few excerpts that Constellation agrees with, and
would like the future SDT to consider: •The Generator Owner or Generator Operator that owns
and/or operates a Generator Interconnection Facility, that is, a sole-use facility that
interconnects the generator to the grid, should not be registered as a Transmission Owner or
Transmission Operator by virtue of owning or operating its Generator Interconnection Facility. â€
¢A Generator Interconnection Facility is considered as though part of the generating facility
specifically for purposes of applying Reliability Standards to a Generator Owner or Generator
Operator. •After review of the existing Transmission Operator requirements that are not
currently applicable to Generator Operators, no existing Transmission Operator requirements
should apply to Generator Operators as a result of the Generator Interconnection Facility.
Individual
Alisha Anker
Prairie Power, Inc.
Yes
No
PPI believes the group has extended the scope too broadly from its initial intent as described in
comments below.
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No
PPI agrees with the first and existing sentence of the Generator Operator definition. However,
the first part of the second sentence regarding operating the Generator Interconnection Facility is
redundant with the first sentence. The second portion of the second sentence regarding
coordinating with the Transmission Operator has been established already in TOP-001 R7.1 and
TOP-003 R1.1 for the purpose of this project.
No
PPI considers the phrase “for SPS relay or control equipment under its control†to be
confusing and ambiguous in the new requirement IRO-005 R13. We suggest deletion of this
phrase maintains the intent of the requirement and removes the unclear reference to the subject
associated with the word “itsâ€. PPI questions why the sub-elements of new requirement
TOP-001 R9 are stipulated in bullet item format rather than sub-requirement format. PPI agrees
with the first portion of new requirement PER-001 R2. Regarding the second portion of new PER001 R2, the Generator Operator is already required to comply with Reliability Coordinator
directives as established in IRO-001 R8 and TOP-001 R3, and further the Generator Operator is
already required to comply with Transmission Operator directives also as established in TOP-001
R3. PPI does not see any benefit in reiterating the Generator Operator responsibility and
authority to follow directives in this new requirement. PPI would suggest stipulating the
Generator Operator be responsible for following directives of the Balancing Authority in a
separate Requirement or sub-requirement, and not lumped into this new requirement.
No
PPI does not agree with the modification to EOP-003 R7. The Generator Operator does not have
load to be shed, therefore none to be coordinated. If the drafting team is intending to require
the Generator Operator to coordinate the underfrequency relay settings on their resources with
load shedding plans established by the Transmission Operator and Balancing Authority, this is an
appropriate requirement. The modification, though, does not accomplish this. PPI questions why
the sustained line outages reported quarterly to the RRO pursuant to FAC-003 R3 by the
Generator Owner, as modified, are not reported to NERC in Requirement 4 of the same
Standard.
No
12 months following Regulatory Approval
12 months following Regulatory Approval
24 months following Regulatory Approval
24 months following Regulatory Approval
12 months following Regulatory Approval
12 months following Regulatory Approval
12 months following Regulatory Approval
12 months following Regulatory Approval
PPI contends this SAR and associated requirement additions and revisions go well beyond the
recommendations from the Group needed to resolve the barrier issue between Transmission
Operator and Generator Operator. The FAC-003 standard revision, so that vegetation
management can be enforced for transmission lines which interconnect generators to
transmission, is really all that is necessary. All these other changes just add confusion to already
overlapped requirements.
Individual
Michelle D'Antuono
Ingleside Cogeneration, LP
Yes
Ingleside Cogeneration, LP believes that the effort by the Ad Hoc Group for Generator
Requirements at the Transmission Interface has generally succeeded in developing criteria
clarifying the ownership and operational responsibilities of registered generation and transmission
entities at their point of interface. This is an important body of work which needs to result in an
end to the forced registration of Generator Owners/Operators (GO/GOP) as Transmission
Owner/Operators (TO/TOP) by Regional Entities.
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No
No. Ingleside Cogeneration, LP believes there is a secondary, but equally important issue which
we believe has not been fully addressed in the proposed SAR. There can be components of the
Generator Interconnection Facility located on the Generator Owner’s property, but are
maintained by the Transmission Owner. An excellent example is the relays protecting the
interconnected transmission line. Although these are usually purchased by the Generator Owner
and are financially carried on their books, in some cases the Transmission Owner performs the
associated maintenance and testing. This arrangement can make sense as the relays are
protecting a transmission system and must properly interact with relays on the other side of the
transmission line through associated communications systems. This kind of arrangement can
lead to a variety of interpretations by auditors even when presented with an Interconnection
Agreement specifying the ownership/maintenance arrangement. We believe that if the
responsibility to a requirement is clearly delineated in a formal document, the associated
collection and presentation of evidence of compliance is part of that responsibility – in this case
the TO owning maintenance and testing of protective relays financially owned by the GO. The
Exclusion statement under Section III.c.4 of the Statement of Compliance Registry Criteria allows
for compliance responsibility to be transferred to another entity provided it registers as the
appropriate entity. In addition, we recognize that Sections 501 and 507 of the NERC Rules of
Procedure allows distribution of responsibility among two or more entities through a Joint
Registration – although that process is designed for tightly connected organizations such as
joint ventures or cooperatives. We recommend these all-or-nothing approaches be modified in
the exclusion as suggested below: A generator owner/operator will not be registered based on
these criteria if responsibilities for compliance with approved NERC reliability standards or
associated requirements including reporting have been transferred by written agreement to
another entity that has registered for the appropriate function for the transferred responsibilities,
such as a load-serving entity, G&T cooperative or joint action agency as described in Sections
501 and 507 of the NERC Rules of Procedure. "Responsibility for individual requirements
applicable to the Generator Interconnection Facility including reporting can be transferred by
written agreement without a change to an entity’s registration."
Yes
Yes
Yes
No
Individual
Katy Mirr
Sempra Generation
Yes
Yes
Yes
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Yes
Yes
No
Sempra Generation commends the efforts of the NERC Ad Hoc Group, and supports the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface, and
Standards Authorization Request addressing the various Standards containing GO/GOP and
TO/TOP Requirements. The Final Report and SARs are products of detailed analysis and
thoughtful consideration of the myriad issues surrounding the reliability implications of ownership
and operation of Generator Interconnection Facilities. It is noteworthy – though hardly
surprising – that, after many months of study, the GO/TO Task Force, a balanced group
comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator
interconnection facilities are operated reliably. When implemented, the recommendations
included in the Final Report and SARs should go a long way toward providing the regulatory and
compliance certainty needed by generators who own or operate Generator Interconnection
Facilities. Accordingly, Sempra Generation encourages the Standards Drafting Team to act
quickly to implement the SARs.
Individual
Robert Ellis
Mesquite Power
Yes
Yes
Yes
Yes
Yes
No
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Group
Electric Market Policy
Jalal Babik
Yes
Yes
Yes
No
We feel it is not necessary to include the phrase “including the Generator Interconnection
Facility†in all the applicable requirements. The term Generator Interconnection Facility is
proposed to be included in the Glossary definitions and the proposed definition of Generator
Operator includes the following language “also operates the Generator Interconnection Facility
and is responsible for coordinating with the Transmission Operator when the facility is energized
or about to be energized to/de-energized from the transmission system†which we feel is
sufficient and superior to having the phrase repeated throughout the applicable standards.
Yes
No
18 months to two years
We feel that, in most cases, such monitoring will only require RTU connectivity of the data points
as well as incorporation into GOP control room displays.
Less than one year
Memo from management should suffice.
two years
Developing the training and providing it while accommodating shift employees will require a
substantial amount of time.
Less than one year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes.
Less than one year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this.
Less than one year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this.
less than one year
Facility should be compliant currently with FAC standards.
less than one year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this.
•EOP-003 - I do not understand the addition of GOP to this standard. Additionally, the
Purpose statement is not in alignment with the additional GOP applicability. •FAC-003 –
Step 4.5 should be clearly identified as a “qualifier†for Generator Owner applicability.
Although not the intent of the standard, as currently drafted, the requirements apply to all
Generator Owners. •MOD-010 – The changes made in this standard are not reflected in the
associated standard, MOD-011 (possibly because MOD-011 is not FERC approved). •MOD-012
– The changes made in this standard are not reflected in the associated standard, MOD-013
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(possibly because MOD-013 is not FERC approved). •PER-001 – The Purpose statement is
not in alignment with the additional GOP applicability.
Individual
Jon Kapitz
Xcel Energy
Yes
Should the definition of Generator Interface Facility indicate that no BES (or any) loads be tapped
between the generator and the GIF operational interface?
There are many other standards development projects underway that are modifying the same
standard. It is unclear as to how the changes will be coordinated amongst the many teams.
Group
ISO RTO Council Standards Review Committee
Ben Li
Yes
No
Please see our comments under Q8.
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator
Operator, but do not agree with the need for the second sentence. The first sentence already
states inclusion of Generator Interconnection Facility. The first part of the second is simply a
repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence.
No
Please see our comments under Q5 where we comment on both the additions and modifications
to the standards.
No
While we generally agree with the proposed wording change, we have a number of comments
the first of which is a timing decision issue. (1) We realize that the SDT needs to make changes
to “approved standards†but there are a number of standards involved in this project whose
newer versions have either received the BoT approval, or about to be adopted by the BoT or at
the stage of being finalized or balloted. To make changes to the soon to be outdated versions is
confusing and will require a subsequent change when FERC approves the standards. We
therefore suggest the SDT to coordinate their changes with the other drafting teams that are
working on the newer versions already or soon to be adopted by the BoT and those that are
being balloted. Alternatively, the SDT may want to post the changes to those FERC approved
standards only, and defer actions on those that have not been approved by FERC and those that
are being revised/balloted until FERC approves them. (2) EOP-001: R7.3 has been changed to
add the term “…, including outages to the Generator Interconnection Facility, to maximize â
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€¦..â€. It is not clear with whom the TOP and the BA should coordinate with and it does not
place a requirement on the entity that is responsible for the Generator Interconnection Facility
outage planning and scheduling. We suggest removing the changes on this requirement all
together. Generator maintenance will include the Generator Interconnection Facility. These are
extra words that are not needed. (3) A number of standards are missing their VSLs. Most VSLs
have similar wording in the requirements so many of them will need to be revised to reflect
changes to the requirements proposed in this project. (4) We do not agree with the modification
to EOP-003 R7. The Generator Operator does not have load shed to coordinate. We believe the
drafting team is intending to require the Generator Operator to coordinate underfrequency relay
settings on their generators with the BA and TOP load shedding plans. We agree this is
appropriate but the modification does not accomplish this. (5) EOP-004 R2 seems to be modified
unnecessarily. System and facilities are already included in the requirement and, thus, would
include the Generator Interconnection Facility. (6) We do not agree adding Generator
Interconnection Operational Interface to R1.3 in EOP-008. The sub-requirement already requires
the contingency plan to consider generation control which would require consideration of the
Generator Interconnection Operational Interface. Furthermore, there is a lack of coordination with
the project to update this standard. A newer, significantly modified version of this standard has
already been through an initial ballot period. (7) IRO-005 R9 modifications are not needed. The
requirement already requires an RC to coordinate pending generation outages. This would have
to include any outage such as the Generator Interconnection Facility. (8) PRC-001: We question
the need for a BA to understand the purpose and limitations of protection schemes associated
with all of the Generator Interconnection Facilities in its area given a BA’s role is to balance
load/generation/interchange which does not require the BA to operate any generator or BES
facilities, or to understand the characteristics or limitations of any equipment. Any potential loss
of one or more generator due to protection or equipment issues will need to be communicated
by the GO or GOP to the BA for consideration in reserve calculation. (9) Many of the changes to
the TOP standard are modifying or adding parallel requirements that the Real-Time Operations
standards drafting team has already proposed for removal. This project needs to be coordinated
with the Real-Time Operations project to assess the need for these additions/modifications. (10)
VAR-001 R8 modifications are not necessary because the TOP is already required to operate
reactive generation scheduling. They can’t do this without considering the Generator
Interconnection Facility.
No
These SAR and associated draft standards changes go beyond what is needed to resolve the
GO/TO GOP/TOP registration issue. The only real changes that are needed are to include adding
GO and GOP applicability in the FAC-003 standard so that vegetation management can be
enforced for lines built to interconnect generators without registering the GO/GOP as a TO/TOP.
All additional changes just add confusion and cause significant coordination issues with other
draft standard changes. This proposed SAR and associated standards’ modifications does not
appear to have been coordinated with any other drafting team. There are many standards and
requirements that are in various states of change. For instance, the TOP standards have been
significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Group
Energy Standards Working Group
Jack Cashin
Yes
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EPSA members, through active participation in many NERC activities including the team that
prepared the report and the attached SAR, are strong advocates of mandatory standards to
protect reliability of the Grid. We also strongly agree that there is a need for greater clarity of
the responsibilities of Generator Owner/Operators and Transmission Owner/Operators at the
Generator Interconnection Interface and thus concur with the direction of this SAR that this
should be achieved without the need for Generator Owner/Operators to be included in the
registry as Transmission Owner/Operators.
Yes
Yes
In particular we support the revised definition of the Generator Interconnection Facility, which
has appropriately incorporated our comments from the draft of the Team’s report
No
We are supportive of most of the new requirements being suggested with the following two
exceptions: IRO-005 R13 which states: R13. The Generator Operator shall immediately inform
the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under
its control. We believe that this proposed additional requirement is redundant as it is already
covered by the requirements of PRC-001-1 AND TOP-001 R10 which states: The Transmission
Operator shall have decision-making authority over operation of the Generator Interconnection
Operational Interface at all times in order to preserve Interconnection reliability. We would
amend the proposed R10 as follows: The Transmission Operator shall have decision-making
authority over operation of the Generator Interconnection Operational Interface at all times in
order to preserve interconnection reliability, unless by exercising that authority such actions
would violate safety, equipment, regulatory or statutory requirements. Under these
circumstances the Generator Operator shall immediately inform the Reliability Coordinator or
Transmission Operator of the inability to perform the directive so that the Reliability Coordinator
or Transmission Operator can implement alternate remedial actions.
No
Comments: see my note re FAC-003 We are supportive of the modified requirements being
suggested with the following exception: FAC-003: We offer the following suggested changes for
greater clarity. 4. Applicability: Replace the proposed sections 4.4 and 4.5 with the following:
4.4. Generator Owner that owns a Generator Interconnection Facility above 200 kV that exceed
two spans from the generator property line or are below 200 kV and deemed critical to the
reliability of the electric system by the Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and
subsequent sections of the standards, it is clear that the use of the words “Generator Ownerâ
€ refers only to the subset of Generator Owners as specified by section 4.4, not to all Generator
Owners included in the NERC Registry.
No
1 year
2 years
2 years
1 year
1 year
1 year
1 year
1 year
We commend the work of the team that produced the report and this SAR and suggest that the
Standard Drafting Team give due deference to the report with the modifications that we have
suggested in questions 4 and 5 above. In addition, EPSA would highlight the following
conclusions that follow from the report: •The Generator Owner or Generator Operator that
owns and/or operates a Generator Interconnection Facility, that is, a sole-use facility that
interconnects the generator to the grid, should not be registered as a Transmission Owner or
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Transmission Operator by virtue of owning or operating its Generator Interconnection Facility â€
¢A Generator Interconnection Facility is considered as though part of the generating facility
specifically for purposes of applying Reliability Standards to a Generator Owner or Generator
Operator •After review of the existing Transmission Operator requirements that are not
currently applicable to Generator Operators, no existing Transmission Operator requirements
should apply to Generator Operators as a result of the Generator Interconnection Facility
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
With the implementation of the new Glossary Terms, this will clarify the dividing point between
GO and TO.
Yes
No
The definition for Generator Interconnection Facility does not fully include the recommendations
of the Ad Hoc Group Conclusions. The first conclusion states that the facility must be 100 KV and
above and more importantly that if there is power flows through this station that do not belong
to the generators or their exclusive station loads, then this station becomes a TO responsibility.
The definition of Transmission somewhat covers the above statement, but still need clarity.
Example: Transmission - An interconnected group of lines and associated equipment in which
network powerflows through this station are associated with the movement or transfer of electric
energy between points of supply and points at which it is transformed for delivery to customers
or is delivered to other electric systems. Generator Interconnection Facility will not contain any of
the above criteria.
Yes
Yes
The modifications at this point appear appropriate.
No
No manpower available at this time to examine all possibilities and scenarios.
Group
E.ON U.S.
Brent Ingebrigtson
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and
therefore does not see the need for auditable reliability standards to be added between the
GO/TO.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and
therefore does not see the need for auditable reliability standards to be added between the
GO/TO.
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No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and
therefore does not see the need for auditable reliability standards to be added between the
GO/TO. Also, it is not necessary to include the phrase “including the Generator
Interconnection Facility†in all the applicable requirements. Since the term Generator
Interconnection Facility is proposed to be included in the Glossary definitions for Generator
Operator, then it would be redundant to also add the phrase throughout the applicable
standards.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and
therefore does not see the need for auditable reliability standards to be added between the
GO/TO.
No
A training program for this would need to be created, procedures approved, implemented, and
instituted at all power plants for all shifts. E.ON U.S. recommends that the addition of PER-002
R3 be coordinated with the existing standard PRC-001 R1, to eliminate redundancy.
Appears redundant with point e) below. There are already generator-outage reporting protocols
in place. This would be an unnecessary addition to existing processes.
In case of overload, the E.ON U.S. GOP has an overload current relay that already removes a
generating unit from the grid immediately. Moreover, it is expected that in most cases an
Interconnection Agreement between the generator and TO that it connects with already contains
language supportive of this.
This SAR should only apply to those separate entity GOPs that already adhere to an OATT. Those
GOPs should be required to register additionally as a TO/TOP. This should not apply to a GOP
within a Corporation that includes TO/TOP that adhere to an OATT, and have already defined an
internal division of responsibilities for the Transmission Interface between the GOP and TOP.
Individual
James Sharpe
South Carolina Electric and Gas
Yes
Yes
Yes
Yes
Yes
No
18 months
12 months
12 months
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18 months
18 months
12 months
18 months
12 months
none
Group
Transmission Owner/Generation Owner
Silvia Parada-Mitchell
The SAR for Project 2010-07 proposes a number of specific changes to existing Reliability
Standards based on the GOTO Report. FPL believes that identifying the exact standards and
language for revision should be the purview of a Standards Drafting Team and not embedded
within the SAR itself. The Standards Drafting Team should be empowered to review the GOTO
Report and make independent recommendations. Many of the questions contained in this SAR
comment form are more appropriate for a Standard’s drafting comment form and not for a
SAR. The place to discuss and evaluate specific wording changes as applicable to standards
revisions should be contained in the Standard Drafting process. The SAR should lay the
foundation for the need for changes, not disseminate or debate exact changes. FPL would
recommend that the sections “Brief†and “Detailed Description†of the SAR should be
amended as follows: “Taking into consideration the GOTO Final Report from November 2009,
the need for revisions to existing standards may exist. The Standards Drafting Team will evaluate
the recommendations of the GOTO Final Report and recommend changes as necessary.â€
Individual
Scott Helyer
Tenaska, Inc.
Yes
Tenaska actively participates in many NERC activities, including the team that prepared the
report and the attached SAR/Draft Standards, and strongly advocates the need for reliability of
the system. We also strongly agree that there is a need for greater clarity of the responsibilities
of Generator Owner/Operators and Transmission Owner/Operators at the Generator
Interconnection Interface and thus concur with the direction of this SAR that this should be
achieved without the need for Generator Owner/Operators to be included in the registry as
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Transmission Owner/Operators.
Yes
Yes
No
TOP-001 R10 should be amended such that the proposed R10 reads as follows: The Transmission
Operator shall have decision-making authority over operation of the Generator Interconnection
Operational Interface at all times in order to preserve interconnection reliability, unless by
exercising that authority such actions would violate safety, equipment, regulatory or statutory
requirements. Under these circumstances the Generator Operator shall immediately inform the
Reliability Coordinator or Transmission Operator of the inability to perform the directive so that
the Reliability Coordinator or Transmission Operator can implement alternate remedial actions.
No
We are supportive of the modified requirements being suggested with the following exception
related to the suggested changes on FAC-003 for which we offer the following modification for
greater clarity: 4. Applicability: Replace the proposed sections 4.4 and 4.5 with the following:
4.4. Generator Owner that owns a Generator Interconnection Facility above 200 kV that exceed
two spans from the generator property line or are below 200 kV and deemed critical to the
reliability of the electric system by the Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and
subsequent sections of the standards, it is clear that the use of the words “Generator Ownerâ
€ refers only to the subset of Generator Owners as specified by section 4.4, not to all Generator
Owners included in the NERC Registry.
No
1 year
2 years
2 years
1 year
1 year
1 year
1 year
1 year
We commend the work of the team that produced the report and this SAR and suggest that the
Standard Drafting Team give due deference to the report with the modifications that we have
suggested in questions 4 and 5 above. In addition, we would highlight the following conclusions
that follow from the report: • The Generator Owner or Generator Operator that owns and/or
operates a Generator Interconnection Facility, that is, a sole-use facility that interconnects the
generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility • A Generator
Interconnection Facility is considered as though part of the generating facility specifically for
purposes of applying Reliability Standards to a Generator Owner or Generator Operator • After
review of the existing Transmission Operator requirements that are not currently applicable to
Generator Operators, no existing Transmission Operator requirements should apply to Generator
Operators as a result of the Generator Interconnection Facility
Individual
Kevin Gillespie
El Dorado Energy LLC
Yes
Yes
Yes
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Yes
Yes
No
El Dorado Energy commends the efforts of the NERC Ad Hoc Group, and supports the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface, and
Standards Authorization Request addressing the various Standards containing GO/GOP and
TO/TOP Requirements. The Final Report and SARs are products of detailed analysis and
thoughtful consideration of the myriad issues surrounding the reliability implications of ownership
and operation of Generator Interconnection Facilities. It is noteworthy – though hardly
surprising – that, after many months of study, the GO/TO Task Force, a balanced group
comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator
interconnection facilities are operated reliably. When implemented, the recommendations
included in the Final Report and SARs should go a long way toward providing the regulatory and
compliance certainty needed by generators who own or operate Generator Interconnection
Facilities. Accordingly, El Dorado Energy encourages the Standards Drafting Team to act quickly
to implement the SARs.
Individual
Patti Metro
National Rural Electric Cooperative Association (NRECA)
Yes
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NRECA is concerned with the decision to use “revisions to the latest versions of the following
standards†that were included in red-line format in this SAR: • BAL-005 • CIP-002 •
EOP-001, -003, -004, -008 • FAC-001, -003, -008, -009 • IRO-005 • MOD-010, -012 â
€¢ PER-001, -002 • PRC-001, -004, -005 • TOP-001, -002, -003, -004, -008 • VAR001, -002 The use of these versions of the standards, many of which have been revised,
approved by the NERC Board of Trustees and filed with FERC emphasizes the flaw in a regulatory
approval process that is not uniform throughout North America. Not all registered entities are
FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon
NERC Board of Trustees approval. Of the standards that are included in this SAR, three projects
not including interpretations have been retired, modified, or new standards created that are now
complied with by some registered entities. The projects include; Project 2006-01 ― System
Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 â
€• Cyber Security ― Order 706 ― CIP-002 through CIP-009. In addition, it is difficult to
determine whether there is any coordination between the activities of this SAR drafting team and
those of the many existing drafting teams that are also revising standards. NRECA understands
the dilemma of how to revise standards in a regulatory environment that has no defined timeline guidelines for approval of standards upon filing with FERC, but reminds NERC, the Standards
Committee and drafting teams that the process must address the varying regulatory approval
processes in North America.
Individual
Greg Rowland
Duke Energy
Yes
Yes
No
• The definitions of Generator Owner and Generator Operator should not be revised, because
every Generator Owner and Generator Operator may not own and operate a Generator
Interconnection Facility, as the revised definitions imply. The revised definition of Generator
Operator also adds a coordination requirement which is more properly included in the
requirements of a standard. • While we are sensitive to the fact that this SAR is attempting to
close a reliability gap, we believe that the definition of Generator Interconnection Facility is too
broad. The Standard Drafting Team should consider limiting it to the voltages defined for the
Bulk Electric System, and other facilities as deemed critical by the Regional Entity. Also, how
does the Regional Entity deem a facility “critical� • The Right-of-Way (ROW) definition
should spell out TO and GO. Suggested rewording: “A corridor of land on which electric lines
may be located. The Transmission Owner or Generator Owner which owns the lines may own the
land in fee, own an easement, or have certain franchise, prescription, or license rights to
construct and maintain the lines.â€
No
See detailed comments under Question 5 below.
No
• General Comment – The Standards Drafting Team (SDT) will need to make sure that
Measures are developed or modified to correspond to new or revised requirements of the
standards. • Process Question – Will the SDT fold these standards revisions into other
projects, or will new versions be created as part of this project? • FAC-003-1 – Applicability
sections 4.4 and 4.5 should be combined to make it clear that the standard only applies to the
Generator Owner’s GIF. Does the 2-span limit mean that there are three towers? What
criteria will the Regional Entity use to deem a GIF critical? The language about the generator
property line is confusing – how does it compare to the Right-of-Way (ROW) definition? In
some cases the TO may own the ROW, while the GO owns the GIF. • FAC-008-1 –
Requirement R1 raises a question regarding whether a GIF can be jointly owned by a TO and a
GO. If a TO is an owner, then the GIF is not a GIF but a transmission facility, right? • FAC009-1 – We don’t think revisions are needed to R1 and R2, since the term “Facilitiesâ€
already implicitly includes GIF. If you don’t agree, then perhaps a more straightforward
approach would be to revise the definition of “Facility†to explicitly include the GIF. •
IRO-005-2 – We think that you don’t need to specifically add the GIF to R9 because it
would have to already be included in the requirement as part of any generation outage
coordination. Under R13 we would change “the Special Protection System†to “any
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Special Protection Systemâ€. We also note that this new R13 propagates the poor language of
R12 (i.e., how does anyone define “a potential failure to operate�). • PER-001-0 –
Applicability section 4.3 should be expanded to make it clear that Requirement R2 only applies
to the Generator Operator with respect to the GIF, and R2 should be likewise revised. The GOP is
already obligated under TOP-001-1 Requirement R3 to comply with RC and TOP directives unless
such actions would violate safety, equipment, regulatory or statutory requirements. Suggested
rewording of Applicability section 4.3 : “Generator Operators –This standard shall apply to
Generator Operators who own a Generator Interconnection Facility.†Suggested rewording of
Requirement R2 : “For Generation Facility Interconnection equipment under their direct
control, each Generator Operator shall provide operating personnel with the responsibility and
authority to implement real-time actions and to follow reliability directives of Reliability
Authorities, Transmission Operators and Balancing Authorities, to ensure the stable and reliable
operation of the Generation Interconnection Facility.†• PER-002-0 - Applicability section 4.3
should be expanded to make it clear that Requirement R2 only applies to the Generator Operator
with respect to the GIF. Suggested rewording of Applicability section 4.3 : “Generator
Operators –This standard shall apply to Generator Operators who own a Generator
Interconnection Facility.†• PRC-001-1 – Changes to PRC-001-1 should probably not be
made right now, because it is already a vague standard, and was the subject of an
Interpretation (Project 2009-30) which was voted down in February. • TOP-003-0 –
Requirement R1 and its sub-requirements are poorly written. We suggest folding R1.3 into R1
with this suggested rewording: “Generator Operators and Transmission Operators shall
provide planned outage information by 1200 Central Standard Time for the Eastern
Interconnection and 1200 Pacific Standard Time for the Western Interconnection, as follows : â€
• TOP-004-2 – We question whether Requirement R7 is appropriate, since by definition the
GIF is not part of the transmission system network and does not fit with the Purpose statement
of this standard. If R7 is retained, then you need to add Generator Operator to the Applicability
section. • TOP-008-1 – Need to add GOPs to the Purpose statement.
No
However the SDT should perform a complete review.
Approximately 3 months.
Depends upon measures and data requirements, but would probably be a short period of time.
Approximately 24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Approximately 24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Approximately 3 months.
Depends upon measures and data requirements, but should be a short period of time.
Approximately 3 months
Depends upon measures and data requirements, but should be a short period of time.
Approximately 3 months
Depends upon measures and data requirements, but should be a short period of time.
Approximately 3 months.
Depends upon measures and data requirements, but should be a short period of time.
Approximately 3 months.
Depends upon measures and data requirements, but should be a short period of time.
Individual
James H. Sorrels, Jr.
American Electric Power
Yes
No
No
It is unclear if the Generator Interconnection Facility definition only includes facilities at 100 kV or
greater or those deemed critical to the Bulk Electric System by the Regional Entity.
No
AEP believes that the only new requirement that should be addressed is in reference to FAC-003.
AEP does not see benefit in expanding the scope of EOP-003, PER-001, and PER-002. With
respect to TOP-004, AEP does not feel the added requirement is necessary as the Generator
Interconnection Facility should be adequately sized to handle the output of the generator. The
added requirement in TOP-008 for notification is redundant with other obligations for the GOP to
notify other entities, such as in COM-002 and TOP-003.
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Yes
AEP feels that a majority of the standards that were modified add clarity. We reserve the right
to comment when the Standard Drafting Team posts the draft Standard(s).
No
At this point in time, AEP cannot identify any other TO/TOP requirements that should be
considered.
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
AEP does not believe that the added requirement is necessary as the Generator Interconnection
Facility should be adequately sized to handle the output of the generator.
Overall, AEP supports the concept of this SAR, but we question the number of new requirements
that are being brought in scope. Some of the requirements added appear to encourage this SAR
to reach farther than the scope of addressing the Generator Interconnection Facilities.
Group
Midwest ISO Standards Collaborators
Jason L. Marshall
Yes
Yes
No
We agree with the first sentence of the definition of Generator Operator. However, the first part
of the second sentence regarding operating the Generator Interconnection Facility is redundant
with the first sentence. The second portion of the second sentence regarding coordinating with
the Transmission Operator is a requirement and already established in requirement X.
No
The requirement additions to the TOP standards parallel requirements that the Real-Time
Operations standards drafting team has already proposed for removal. This project needs to be
coordinated with the Real-Time Operations project.
No
We do not agree with the modification to EOP-003 R7. The Generator Operator does not have
load shed to coordinate. We believe the drafting team is intending to require the Generator
Operator to coordinate underfrequency relay settings on their generators with the BA and TOP
load shedding plans. We agree this is appropriate but the modification does not accomplish this.
EOP-004 R2 seems to be modified unnecessarily. System and facilities are already included in
the requirement and, thus, would include the Generator Interconnection Facility. We do not
agree adding Generator Interconnection Operational Interface to R1.3 in EOP-008. The subrequirement already requires the contingency plan to consider generation control which would
require consideration of the Generator Interconnection Operational Interface. Furthermore, there
is a lack of coordination with the project to update this standard. A newer, significantly modified
version of this standard has already been through an initial ballot period. IRO-005 R9
modifications are not needed. The requirement already requires an RC to coordinate pending
generation outages. This would have to include any outage such as the Generator
Interconnection Facility. Many of the changes to the TOP standard are modifying requirements
that the Real-Time Operations standards drafting team has already proposed for removal. This
project needs to be coordinated with the Real-Time Operations project. VAR-001 R8
modifications are not necessary because the TOP is already required to operate reactive
generation scheduling. They can’t do this without considering the Generator Interconnection
Facility.
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No
These SAR and associated draft standards changes go beyond what is needed to resolve the
GO/TO GOP/TOP registration issue. The only real changes that are needed are to include adding
GO and GOP applicability in the FAC-003 standard so that vegetation management can be
enforced for lines built to interconnect generators without registering the GO/GOP as a TO/TOP.
All additional changes just add confusion and cause significant coordination issues with other
draft standard changes. This proposed SAR and associated standards’ modifications does not
appear to have been coordinated with any other drafting team. There are many standards and
requirements that are in various states of change. For instance, the TOP standards have been
significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Individual
James Manning, Bob Beadle, Doug White, and Richard McCall
North Carolina Electric Membership Corporation
Yes
Yes
No
NCEMC seeks clarification from the ad hoc team regarding the definition of Generation
Interconnection Facility (GIF), especially regarding the option for ownership of the GIF. The way
the definition currently reads leaves the interpretation that it might be optional for the Generator
Operator to own the GIF. We are not sure that the Ad Hoc team intended this possible
conclusion, which in our opinion, could completely change the scope of this SAR (in the case
where the GOP does NOT own the GIF). If that is the intent of the Ad Hoc team or SDT, then the
definition of Generator Operator should be changed to reflect the "option" of the GOP owning the
GIF versus someone else like the Transmission Owner/Operator. Also, the second sentence of the
GOP definition is not needed in our opinion since it is a requirement of the standards and as such
requirements are not usually a part of the NERC definition. Other definitions we suggest
changing are as follows: Vegetation Inspection - The systematic examination of a Right-of-Way
to document vegetation conditions. The main reason for the change in definition for ROW was the
proposed use of the non-capitalized term "electric line". Since the use of that phrase sometimes
means distribution lines as well as transmission, we suggest staying with the capitalized NERC
terms for better clarity. Right-of-Way (ROW) - A corridor of land on which a Transmission Line or
Generator Interconnection Facility may be located. The owner of the Transmission Line or
Generator Interconnection Facility may own the land in fee, own an easement, or have certain
franchise,prescription, or license rights to construct and maintain lines.
No
We agree with most of the new requirements with the exception of two: 1) New requirement R9
of TOP-001 appears to be very similar to existing requirements of TOP-001 (req R7) and TOP003 (req R1). Further clarification is needed to distinguish the differences between this new
requirment and existing requirements. 2) New requirement R5 of TOP-008 directs the GOP to
disconnect the GIF when “safety is jeopardized†or… which triggers the immediate
question: Who’s safety does the Ad Hoc group refer to, the personnel of the GO/GOP or the
safety of the transmission system or its personnel or both possibly? Please clarify. If it the safety
of the transmission, its personnel or the system grid in general, then why would it not be the
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TOP's responsibility to provide a directive of this nature since the TOP would have a greater
perspective/visibility than the GO/GOP of the system operating conditions in real time?
No
We agree with most all of the modified requirements with one exception: For FAC-003, regarding
the "two-span criteria" or "about 0.5 miles" test for generator applicability, we would like the ad
hoc team to consider providing more direction or greater specificity that makes a GIF of two or
less spans to become exempt, while one of greater than two spans (0.5 mile) but less then 5
spans (0.8 miles) to suddenly become subject to the FAC-003 standard requirements. The
"generator's line-of sight" rule as described in response to item #3 in the Final Report in our
opinion should be clearly specified in the FAC-003 proposed standard change at a minimum to
avoid mis-interpretations. Also, regarding item #10 issue in the report, we would like the ad hoc
team to consider proposing a 4th proposal which would be a hybrid between Proposal 2 and
Proposal 3 as reported within the Final Report which would provide a “bright-line test†as to
what generators are exempt or not to the FAC-003 standard, rather than solely relying on
Proposal 2 which relys on the physical attributes of the GIF in ruling out generators subject to
FAC-003. If the GIF is 3-4 spans or 0.53 miles in length, but still within the "line of sight" of the
GOP, then allow the GOP working with the RE and TOP to rule out smaller generators that are
immaterial to the reliability of the grid.
No
12 months
12 months
12 months
12 months
12 months
12 months
12 months
12 months
NCEMC is concerned with the decision to use “revisions to the latest versions of the following
standards†that were included in red-line format in this SAR: • BAL-005 • CIP-002 •
EOP-001, -003, -004, -008 • FAC-001, -003, -008, -009 • IRO-005 • MOD-010, -012 â
€¢ PER-001, -002 • PRC-001, -004, -005 • TOP-001, -002, -003, -004, -008 • VAR001, -002 The use of these versions of the standards, many of which have been revised,
approved by the NERC Board of Trustees and filed with FERC emphasizes the flaw in a regulatory
approval process that is not uniform throughout North America. Not all registered entities are
FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon
NERC Board of Trustees approval. Of the standards that are included in this SAR, three projects
not including nterpretations have been retired, modified, or new standards created that are now
complied with by some registered entities. The projects include; Project 2006-01 ― System
Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 â
€• Cyber Security ― Order 706 ― CIP-002 through CIP-009. In addition, it is difficult to
determine whether there is any coordination between the activities of this SAR drafting team and
those of the many existing drafting teams that are also revising standards. NCEMC understands
the dilemma of how to revise standards in a regulatory environment that has no defined timeline guidelines for approval of standards upon filing with FERC, but reminds NERC, the Standards
Committee and drafting teams that the process must address the varying regulatory approval
processes in North America.
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
No
FAC-003 should not be applicable to Generator Owners / Operators. The intent of all of the
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standards is to avoid an Adverse Reliability Impact, or as the FPA Section 215(a)(4) defines â
€œreliable operations†as: “operating the elements of the bulk-power system within
equipment and electric system thermal, voltage and stability limits so that instability,
uncontrolled separation, or cascading failures of such systems will not occur as a result of a
sudden disturbance, including a cybersecurity incident, or unanticipated failure of system
elements.†Radial Facilities serving only generating plants when tripped will not threaten an
Adverse Reliability Impact or we would be hard pressed to run that generation in the first place.
FMPA believes the intent of the standard is to prevent a cascading event where, if a line trips,
another line loads heavily increasing the sag of that line, which may sag into un-cleared
vegetation, causing the second line to trip, which may in turn cause heavily loading on a third
line, etc. If a line trips in the transmission network, radial Facilities from generating plants will
not have their loading changed much at all (since they are radial) and will not participate in this
sort of “thermal†cascading event. Hence, there is no cause to regulate vegetation
management of radial Facilities to generating plants since the system is always planned and
operated to that potential contingency anyway and there is no danger of an Adverse Reliability
Impact. Regulating vegetation management on radial Facilities is beyond the scope of the Federal
Power Act Section 215. Generator Owners / Operators are still incented to perform adequate
vegetation management without the need for regulation because any outage of the plant results
in lost opportunity costs to the plant.
Yes
Yes
No
The modification of EOP-003-1, R7 is inconsistent with the requirement. The original requirement
requires the BA and TOP to coordinate with others (presumably DPs, TOs and GOPs) in their area
for various automatic action (e.g., UFLS, automatic tripping of cap banks, and frequency
capabilities of generators for instance). The GOP has no “area†to coordinate and no one
within its area to coordinate with. So, it is the BA and TOP that coordinate within their area, not
the entities embedded within the BA or TOP area. Otherwise, we ought to add at a minimum
DPs, LSEs, and TOs to the list. The modifications to EOP-004-1 R2; FAC-001-0 R1.1; FAC-0081; FAC-009-1; MOD-010, MOD-012, PRC-001, PRC-004; PRC-005; TOP-001-1 R7; TOP-002 R3
and R18; TOP-003 R1 and R1.1; and VAR-002 R3.2 are redundant with no need to specifically
call out the Generator Interconnection Facility. The interconnection facilities are facilities and
already included in the term “on its system or facilities†and “generating facilitiesâ€, etc.
And, the Generator Owner and Operator are already responsible for their interconnection facilities
in the definition of those Entities. Specifically calling out the interconnection facilities calls into
question why other facilities are not specifically called out. As discussed in the response to #2
above, addition of the Generator Owner to FAC-003 over-steps Federal Power Act Section 215
since radial transmission lines to generating plants will not participate in a cascading outage
since the loading of radial facilities to power plants will not change significantly with outages on
the interconnected system.
No
The amount of time it takes to compile documentation to fulfill the data retention requirements
of the requirement
For most of these new requirements, the Entities are most likely fulfilling the requirements, but,
may be missing the documentation to prove that they are doing so. So, to be auditably (â
€œfullyâ€) compliant, the Entities will need the amount of time it takes to build up sufficient
evidence of compliance. This may only be a month to develop documentation, to a longer period
of time to prove periodicity (e.g., a PRC-005 type of requirement – not PRC-005 itself – but
a requirement that may need to be done periodically such as training to show that it is done
periodically.
See above
See above
See above
See above
See above
See above
See above
See above
See above
See above
See above
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See above
See above
See above
Group
Bonneville Power Administration
Denise Koehn
Yes
Yes
Yes
Yes
However, believe there is a problem with #8 referring to TOP-008. The solution to the generator
facilitiy line overload may be a transmission system problem so the Generatior should not
disconnect unless the TOP directs it to do so(confer unless a safety issue). Also, TOP-001 needs
careful work. The transmision system doesn't want environmental issues turning off generators
during emergency or critical transmission conditions.
Yes
No
1 year, if agreements need to be renegotiated.
6 months
2-3 years, depending on the extent of equipment involved and size of facility.
1 year, if agreements need to be renegotiated.
1 year, if agreements need to be renegotiated.
6 months.
0 months.
1 year, if agreements need to be renegotiated.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
Yes
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator
Operator, but do not agree with the need for the second sentence. The first sentence already
states inclusion of Generator Interconnection Facility. The first part of the second is simply a
repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence. (2)
Generator Interconnection Facility: The Sole-use facilities should include those which transmit
power to redial customer loads if such facilities do not form a part of the connection to multiple
transmission facilities that are subject to network power flows.
No
Please see our comments under Q5 where we comment on both the additions and modifications
to the standards.
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(1) We realize that the SDT needs to make changes to “approved standards†but there are
a number of standards involved in this project whose newer versions have either received the
BoT approval, or about to be adopted by the BoT or at the stage of being finalized or balloted. To
make changes to the soon to be outdated versions is confusion and will require a subsequent
change when FERC approves the standards. We therefore suggest the SDT to also mark up
those which have newer versions already or soon to be adopted by the BoT and those that are
being balloted. Alternatively, the SDT may want to post the changes to those FERC approved
standards only, and defer actions on those that have not been approved by FERC and those that
are being revised/balloted until FERC approves them. (2) EOP-001: R7.3 has been changed to
add the term “…, including outages to the Generator Interconnection Facility, to maximize â
€¦..â€. It is not clear whom the TOP and the BA should coordinate with and it does not place a
requirement on the entity that is responsible for the Generator Interconnection Facility outage
planning and scheduling. We suggest to add the appropriate responsible entity (Generator
Owner?) to the Applicability Section, and add this entity to R7.3. (3) In EOP-008 R1.3, is it the
intent of the revised requirement that the plan address monitoring and control of ALL Generator
Interconnection Operational Interface[s] or just the critical ones (as with the critical transmission
facilities)? (4) R10 of TOP-001 is not written in the form of a requirement. We suggest replacing
“have†with “exerciseâ€. Thus, the requirement would read “The Transmission
Operator shall exercise decision-making authority over operation of the Generator
Interconnection Operational Interface…†(5) TOP-004: The Applicability Section needs to be
revised to add Generator Operator to reflect the new requirement R7. We also suggest the SDT
to evaluate if there is an alternative or more suitable place for this requirement than the TOP
standard. (6) A number of standards are missing their VSLs. Most VSLs have similar wording in
the requirements so many of them will need to be revised to reflect changes to the requirements
proposed in this project.
No
Group
Pepco Holdings, Inc - Affiliates
Richard Kafka
Yes
It is difficult to say if there is a “reliability-related needâ€. Most GOs operate and maintain
their Generator Interconnection Facility in the same manner as the rest of their generation
facilities. It is beneficial to differentiate between the “Generation Interconnection Facilityâ€
and the “Transmission†system so that GOs do not have to be registered as TOs.
Yes
Defining “Generator Interconnection Facility†in the glossary is a good idea. Going beyond
this to specifically note this term in so many other standards seems unnecessary since other
individual devices are not noted in so many other locations. If “Generator Interconnection
Facility†is included in all other Generating Facilities, this may simplify the process.
Yes
“Generator Interconnection Facility†is useful to allow GOs to be distinguished from TOs and
their responsibilities. “Generator Interconnection Operational Interface†is also known as the
“Point of Interconnect†by the RTO. This may be an alternate name that could be used to
make things standard.
Yes
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Application of FAC-003 for Gen Interconnect Facilities that are "two spans, generally 1/2 mile or
more past the property line" is reasonable as long as the "property line" remains in the definition.
OK.
Yes
There should be a clause that the TO shall be responsible for FAC-003 activities inside the TO's
substation regardless of ownership of the Generation Interconnection Facility so we don't have to
coordinate entry, etc. and they will likely have this handled for the bulk of their property anyway.
R3 quarterly reporting of outage caused by vegetation is excessive for GOs. GOs would probably
survey and cut as needed their Right of Ways at least once a year and probably already do so.
TOs probably perform vegetation management on a multi-year cycle, so they might need to note
quarterly if there is a veg. incident that occurs one or two quarters before the next round of
survey/management on that line.
No
No SPS currently in system.
These responsibilities and authorities are already in place for other standards.
0-2 years
Currently establish training based on the RTO requirements. It would be Conectiv’s policy to
continue this training for this requirement. If other training is imposed upon the Entities, it may
require up to two years to develop and initiate full training.
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted
by NERC, there may be a need to have time to develop new programs and policies to comply
with additional requirements.
0-2 years
Coordination is required for the TOP to notify the GO/GOP of the decisions being implemented.
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted
by NERC, there may be a need to have time to develop new programs and policies to comply
with additional requirements.
0-2 years
Entity currently operates within the facility ratings as required under FAC. If additional
requirements are instituted by NERC, there may be a need to have time to develop new
programs and policies to comply with additional requirements
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted
by NERC, there may be a need to have time to develop new programs and policies to comply
with additional requirements.
Group
First Wind
Mary Jo Cooper
Yes
Yes
The proposed SAR modification set is the responsible approach to resolve gaps Generator
Interconnection Facility gaps identified by the industry. The functions required of an Owner(s)
and Operator(s) of facilities used to connect generation to the BES (Generator Interconnection
Facilities) are not the same as the functions required to own and operate Transmission and
should not be considered to be the same. We commend the task force for coming up with a
reasonable approach that directly addresses reliability without requiring GO and GOPs to perform
activities that have no bearing on the reliability of the BES.
No
We recommend the definition of Generator Interconnection Facility be modified. “Generator
Interconnection Facility (NEW) A facility used for the sole purpose of connecting the generating
unit(s) to the transmission grid. In this regard, the sole-use facility only transmits power
associated with the interconnecting generator(s), whether delivered to the grid or delivered to
the generator(s) for station service or auxiliary load, or delivered to meet cogeneration load
requirements. The purpose of the above modification is to account for the situations where a
Generator Operator may have many units, such as wind turbines, all using the same Generator
Interconnection Facility to connect to the transmission grid. Additionally, we feel it is irrelevant if
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the Generating Unit is owned by one or the same owners. Two scenarios explain why multiple
generators using the same Generator Interconnection Facility does not serve a function of a TO
or TOP. Scenario 1 Each Generator Operator is connected to the Transmission Operator through
an independent Generator Interconnection Facility. There is no need for the Generator Operators
to coordinate their operations with one another because their operations do not impact common
facilities. However, there may be a need for the Transmission Operator to coordinate its
instructions to the Generator Operators (if they issue voltage schedules, for example). When it
becomes necessary for the Transmission Operator to communicate instructions to the Generator
Operators, it is necessary for the Transmission Operator to communicate with each of the
Generator Operators. Scenario 2 Generator Operator A is connected independently, but
Generator Operators B and C share a common Generator Interconnection Facility. In this case, it
is necessary for Generators B and C to coordinate their operations. It is not necessary to
designate either GO_B or GO_C as the “operator†of the Generator Interconnections Facility.
Rather, it is most appropriate to place the obligation to coordinate operations on both parties. By
placing the obligation on both parties, they share an equal burden to comply with the applicable
standards. Placing the obligation to coordinate operations on both GO_B and GO_C does not
increase the burden to the Transmission Operator. If there is trouble at the point of interconnect
substation, the Transmission Operator might need to coordinate operations with GO_A, GO_B
and GO_C in either Scenario 1 or Scenario 2. If in Scenario 2, the Transmission Operator only
issued instructions to GO_A and GO_B, they could not be sure that GO_C would receive the
instructions. Furthermore, since GO_B is not a Transmission Operator, they lack the authority to
issue instructions to GO_C. We recommend an additional requirement to resolve coordination
between generators. For example “Generator Operators interconnected through a common
Generator Interconnection Facility shall coordinate their operations.â€
No
We feel it is not necessary to include the phrase “including the Generator Interconnection
Facility†in all the applicable requirements. The term Generator Interconnection Facility is
proposed to be included in the Glossary definitions and the proposed definition of Generator
Operator includes the following language “also operates the Generator Interconnection Facility
and is responsible for coordinating with the Transmission Operator when the facility is energized
or about to be energized to/de-energized from the transmission system†which we feel is
sufficient and superior to having the phrase repeated throughout the applicable standards.
Yes
No
Immediately unless status requires change to additional requirements which might be 18 months
to two years)
The Generator Interconnection Facilities are already considered to be part of our Generator Plant
and therefore have already been included in our existing compliance program.
Less than 1 year
Memo from management should suffice.
2 years
Developing the training and providing it while accommodating shift employees will require a
substantial amount of time.
Less than 1 year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes. Additionally, the Generator Interconnection Facility is already considered to be part of
the Generating Facility and is likely already part of our existing compliance program.
less than 1 year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this because the Generator
Interconnection Facility is already considered to be part of the Generating Facility.
less than 1 year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this.
less than 1 year
The Generator Interconnection Facility is already considered to be part of the Generator Unit and
the facility should be compliant currently with FAC standards.
less than 1 year
The Generator Interconnection Facility is already considered to be part of the Generator Unit.
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or
DP that it connects with already contains language that supports this.
FAC-003 – Step 4.5 should be clearly identified as a “qualifier†for Generator Owner
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applicability. Although not the intent of the standard, as currently drafted, the requirements
apply to all Generator Owners. Additionally we recommend modifications to address a disqualifier
if the plant is located in an environment whose natural environment would prevent vegetation
from growing that could interfere with the reliability of the bulk Electric System. The following
changes are recommended. 4.4. Generator Owner. 4.5. This standard shall apply to the
Generator Interconnection Facility above 200 kV that exceed two spans from the generator
property lineor are otherwise deemed critical by the Regional Entity below 200 kV (subject to the
two-span criteria.). This standard does not apply to all Generator Interconnection Facilities
outside this threshold and those facilities located in an area whose environment would prevent
vegetation from growing. A generating facility located underground, in the high desert or within a
fully developed urban area where vegetation disturbances could not occur should not be required
to have a vegetation management program. • MOD-010 – The changes made in this
standard are not reflected in the associated standard, MOD-011 (possibly because MOD-011 is
not FERC approved). • MOD-012 – The changes made in this standard are not reflected in
the associated standard, MOD-013 (possibly because MOD-013 is not FERC approved). • PER001 – The Purpose statement in the Standard needs to be modified to include GOP. • PER002 – The Purpose statement in the Standard needs to be modified to include GOP. We
recommend the addition of PER-002 R3 is coordinated with the existing standard PRC-001 R1 to
eliminate redundancy. While PER-002 R3 more clearly calls for training, PRC-001 R1 implies
training. The two standards should be combined into one training requirement. PRC-001 R1 â
€œEach Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area.†We
recommend retiring PRC-001 R1 and modifying the proposed standard PER-002 R3 as shown
below: Each Generator Operator shall implement an initial and continuing training program for all
operating personnel that are responsible for operating the Generator Protection System
Equipment, including the Generator Interconnection Facility that verifies the personnel’s
ability and understanding to operate the equipment in a reliable manner. • • TOP-002 –
Requirement R14 contains sub-requirements R14.1 and R14.2 that were retired August, 1, 2007.
Suggest deleting the retired requirements with the proposed revision. • TOP-004 –
Requirement R7 has been added for the Generator Operator; however, the Generator Operation
has not been added to the Applicability. • TOP-008 – The Purpose statement in the
Standard needs to be modified to include GOP.
Individual
Jason Shaver
American Transmission Company
Yes
Yes
Yes
No
Clarify the definition of generator interconnection facility to include who this applies to as shown
in the conclusions above in #3. A Generator Interconnection Facility is considered as though part
of the generating facility specifically for purposes of applying Reliability Standards to a Generator
Owner or Generator Operator.
Yes
For FAC-009 [Establish and Communicate Facility Ratings], we believe that the additional
wording to highlight that the term “Facilities†includes “Generation Interconnection
Facilities†is superfluous, and therefore, it should not be added. The proposed new and revised
definitions provide more than enough clarity For MOD-010 [Steady State Data for System
Modeling], we believe that the additional wording of “for plant and Generator Interconnection
Facilities†is superfluous, and therefore, it should not be added. The proposed new and revised
definitions provide more than enough clarity. For MOD-012 [Dynamic System Data for System
Modeling], we believe that the additional wording of “for plant and Generator Interconnection
Facilities†is superfluous, and therefore, it should not be added. The proposed new and revised
definitions provide more than enough clarity.
No
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Individual
Laura Zotter
ERCOT ISO
Yes
Yes
The proposed language in Requirements 9 and 10 (hereafter R9 and R10) for NERC Standard
TOP-001-X, Reliability Responsibilities and Authorities, clouds the responsibilities among different
functional entities that are and are not held accountable to this Standard. Specifically, the first
part of the sentence in R9 states: “The Generator Operator, in accord with the expectations
defined by the Transmission Operator, shall coordinate…†This statement is overly broad and
vague. For instance, is the statement meant to refer to Interconnection Agreements that have
been entered into between Generator Operators and Transmission Operators? Or, is the
statement intended to include other agreements as well? In addition, there are items listed in R9
(i.e., switching elements, outage planning, and real-time and anticipated emergency conditions)
which are normally the responsibilities of the Transmission Owner and/or the Reliability
Coordinator; however, NERC Standard TOP-001-X is not applicable to the Transmission Owner
or the Reliability Coordinator. Also, the item “other conditions mutually agreed-upon by the
Generator Operator and Transmission Operator†is vague and ambiguous and should be
clarified in order not to confuse tasks that may be more aligned with the responsibilities of the
Transmission Owner or the Reliability Coordinator. Furthermore, R9 and R10 strongly imply and
explicitly give the Transmission Operator authority to take action “in order to preserve
Interconnection reliability.†This type of wide-area authority is meant to describe Reliability
Coordinator-related obligations. The NERC Function Reliability Model is clear in defining the
function and tasks of reliability operations. The Reliability Coordinator is responsible, in concert
with other Reliability Coordinators, for the Interconnection as a whole; not the Transmission
Operator. Lastly, it is unclear how an entity registered for multiple functions (for example,
Reliability Coordinator and Transmission Operator) would be held accountable under this NERC
Standard. If the intent is that R9 and R10 are to be the obligations only of those functional
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entities for which the NERC Standard is applicable, then the language in the NERC Standard
should clearly state that intent.
Individual
Darcy O'Connell
California ISO
Yes
No
Adding language in several standards actually creates confusion rather than provide clarity. For
example, EOP-003-1 (Load Shedding Plans) applies in situations when there is insufficient
generation or transmission, requiring load shedding to avoid risk of uncontrolled failure of the
interconnection. This function is generally accomplished through under frequency relay settings
which will drop a pre-determined amount of load to maintain generation/load balance. Involving
the Generator Operator to comply with this standard is unnecessary and may even complicate
matters because the BA and the TOP will now have to coordinate with GOPs. Other similar
examples are EOP-001-0, EOP-004-1, and TOP-001-1 where adding “Generator
Interconnection Facility†does not add clarity but is rather redundant, and may create
interpretation issues.
No
The definition for “Generator Interconnection Facility†(GIF) is not consistent with either
Conclusion #1 of the Adhoc Group’s final report, or with “Applicability 4.5†added under
FAC-003-1. Conclusion #1 mentions “Generator Interconnecting Facilities operating at a
voltage of 100 kV or greater or those deemed critical to the Bulk Electric System by the Regional
Entity…†and Applicability 4.5 mentions “Generator Interconnection Facility above 200 kVâ
€¦ or are otherwise deemed critical by the Regional entity below 200 kV...â€. In both these
instances it appears that the Adhoc Group is emphasizing those Generator Interconnection
Facilities that are either part of the Bulk Electric System (BES) or deemed critical by the Regional
entity. Therefore, we suggest modifying the definition as follows: First sentence, after the word
grid, add “above 200 kV or otherwise deemed critical by the Regional entity below 200 kVâ€.
Yes
No
Please see our comments under Question 2 above. In addition, with regard to the proposed
change to Standard PRC-001, the California ISO (CAISO) questions the need for a BA to
understand the purpose and limitations of protection schemes associated with all of the
Generator Interconnection Facilities in its area given a BA’s role is to balance
load/generation/interchange which does not require the BA to operate any generator or BES
facilities, or to understand the characteristics or limitations of any equipment. Any potential loss
of one or more generator due to protection or equipment issues will need to be communicated
by the GO or GOP to the BA for consideration in reserve calculation
No
We are not a GOP and hence we are unable to comment on this and other questions addressing
the GOP compliance. However, the CAISO has the following comments on the effort required for
other aspects of this Project: • As discussed under the answer to Question 5 above, it is not
clear if the proposed changes to PRC-001 will require the Balancing Authority (BA) to understand
the purpose and limitations of protection schemes associated with all of the Generator
Interconnection Facilities in its area, even if such facilities are not under the control of the BA. If
this is the case, significant and time-consuming effort will be required to identify the technical
details of all of the Generator Interconnection Facilities in the BA and develop a training program
to train applicable personnel on them. This is estimated to require up to 24 months. • If the
proposed changes are approved they will affect 16 Standards affecting CAISO registrations. Most,
if not all, of these changes will require modifications to the Reliability Standards Agreements
(RSAs) between the CAISO and its Participating Transmission Operators to reflect the new
wording and any delegated tasks. This may require 12 to 24 months to implement.
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It does not appear that any of the Measures in the proposed Standards have been revised to
reflect the new and/or revised requirements.
Individual
Alice Murdock
Xcel Energy
Yes
Should the definition of Generator Interface Facility indicate that no BES (or any) loads be tapped
between the generator and the GIF operational interface?
There are many other standards development projects underway that are modifying the same
standard. It is unclear as to how the changes will be coordinated amongst the many teams.
Group
PSEG Companies
Kenneth D. Brown
Yes
Yes
Yes
Yes
Yes
No
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The PSEG Companies support this approach to ensure that all components of the BES are
adequately covered by the reliability standards. The drafting team has done a good job of
identifying the appropriate areas of concern.
Individual
Marcus Lotto
Southern California Edison co.
Yes
Yes
Yes
Additional clarification would be useful as it/ they would cut down on future requests for
interpretation... i.e provide a specific threshold for the proposed Generator interconnection
Facility definition
Yes
Additional clarification would be useful as it/ they would cut down on future requests for
interpretation.
Yes
Additional clarification would be useful as it/ they would cut down on future requests for
interpretation
No
Do not feel that this question is in the scope of Project 2010-07 as written
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
3yrs
Pls refer to question No. 8
SCE believes that implementing changes type of changes proposed in 2010-07 should be looked
at as a whole/ one entire project rather than piece meal as alluded to in question number 7 of
the comments form. As such, it is the company’s position that approximately 3yrs is right
amount of time to reliably implement the proposed revisions to the suite of standards as
identified in Project 2010-07. A 3 yr timeline would enable the project to be fully scoped out and
budgeted, and allow for: completion of the necessary engineering studies; design, procurement
and construction of any new facilities necessitated by the revisions; development of any new
operations and communications procedures with respect to both the transmission and generation
facilities; and the training of personnel related to any new procedures.
Group
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Checkbox® 4.4
Kansas City Power & Light
Michael Gammon
No
There is a need to bring clarity to the Reliability Standards regarding the delineation of what the
Generator Owner and Generator Operator is responsible for and for definitions distinguishing
between Generator Operators at Power Plants and “Generator Operator†as the “Power
System Operator†directing a fleet of generators in a balancing area. I do not believe reliability
of the interconnected grid has suffered as a result of the shortcomings of the Reliability
Standards in this regard as the electric industry has continued to operate in a responsible
manner.
Yes
No
I believe the intent of what has been proposed here is to define the term, “Generator
Operator†to mean the Operator that operates units directly at a power station. With that in
mind, although the proposed definition is close, I believe the interaction with the Transmission
Operator only in the definition makes this confusing. Recommend consideration of the following
definition: The entity that operates generating unit(s) and the Generator Interconnection Facility
and performs the functions of supplying energy and reactive power as directed by the Balancing
Authority and the Transmission Operator. The Generator Operator may also operate the
Generator Interconnection Facility and is responsible for coordinating with the Balancing
Authority and the Transmission Operator when the facility is energized or about to be energized
to/de-energized from the transmission system. In addition, recommend adding the generating
station property line to the defintion for Generator Interconnection Facility for clarity: Sole-use
facility that leaves generator property line for the purpose of connecting the generating unit(s) to
the transmission grid. In this regard, the sole-use facility only transmits power associated with
the interconnecting generator, whether delivered to the grid or delivered to the generator for
station service or auxiliary load, or delivered to meet cogeneration load requirements.
No
• PER-001, R1: The language proposed for PER-001, R1, infers the Generator Operator is able
to take independent actions regarding the “Generation Facility†and the Generator
Interconnection Facility. There is no definition for Generation Facility in this proposal or currently
in the NERC Glossary. At any rate, do not agree with the Generator Operator taking any
independent actions other than those to monitor and maintain the safe operation of a generating
unit for the production of energy and reactive power. • PER-002, R3 (Proposed here): This
infers again the Generator Operator taking independent actions with regard to equipment within
the Generator Interconnection Facility. Although, the Generation Interconnection Facility is
defined properly, that does not mean the Generator Operator is the control authority over that
equipment. It is not uncommon for the Generator Operator to operate equipment within the
Generator Interconnection Facility at the direction of the Transmission Operator. Recommend
consideration be given to modify this requirement to reflect that. • TOP-001, R9 and R10
(Proposed here): This infers again the Generator Operator taking independent actions with regard
to equipment within the Generator Interconnection Facility. Although, the Generation
Interconnection Facility is defined properly, that does not mean the Generator Operator is the
control authority over that equipment. It is not uncommon for the Generator Operator to operate
equipment within the Generator Interconnection Facility at the direction of the Transmission
Operator. Recommend consideration be given to modify these requirements to reflect the
Transmission Operator can be the authority over the equipment within the Generation
Interconnection Facility but that the Generator Operator may operate that equipment at the
direction of the Transmission Operator.
Yes
No
Not at this time.
12 months
Basically this is a training issue. It takes time to prepare the training materials and to train all
Generator Operators considering shift schedules and to implement the training as part of an
ongoing process.
N/A
The Generator Operator should be operating equipment within the Generator Interconnection
Facility at the direction of the Transmission Operator.
N/A
The Generator Operator should be operating equipment within the Generator Interconnection
Facility at the direction of the Transmission Operator.
6 months
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If this is not already going
6 months
If this is not already going
6 months
If this is not already going
6 months
If this is not already going
6 months
If this is not already going
No other comments.
on, this should not take long to implement.
on, this should not take long to implement.
on, this should not take long to implement.
on, this should not take long to implement.
on, this should not take long to implement.
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Consideration of Comments on Generator Requirements at the
Transmission Interface — Project 2010-07
The GOTO Drafting Team thanks all commenters who submitted comments on the proposed
SAR and modifications to several reliability standards and NERC Glossary terms associated
with the recommendations of the Generator Requirements at the Transmission Interface Ad
Hoc Group, embodied in Project 2010-07. These standards were posted for a 30-day public
comment period from February 12, 2010 through March 15, 2010. The stakeholders were
asked to provide feedback on the standards through a special Electronic Comment Form.
There were 41 sets of comments, including comments from more than 80 different people
from over 60 companies representing 7 of the 10 Industry Segments as shown in the table
on the following pages.
In this report, comments have been organized by question number. All comments may be
reviewed in their original format on the following web page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Based on stakeholder comments, along with discussions with FERC and NERC staff, the SAR
drafting team (SAR DT) made the following modifications to the SAR:
•
Gave the Standard Drafting Team (SDT) the flexibility to include additional standards
not originally identified in the Ad Hoc Task Force Report
•
With respect to new terms and modifications of definitions of terms, the SAR DT
made it clearer that the SDT can adopt proposals as indicated in the Ad Hoc Task
Force Report or modify them to address stakeholder concerns
•
Gave the SDT the option of merging the Ad Hoc Task Force’s proposed changes into
one new standard or an existing standard(s) if deemed appropriate
•
Language changes for clarity
Some commenters indicated that the SAR as written was too broad, but the SDT believes
that giving the SDT as many options as possible is advantageous. The SDT will be the team
to ultimately determine which standards should be modified.
Many commenters made specific recommendations for modifications to standards. The SAR
DT has compiled those comments for use during the next phase of this project, standard
drafting. In particular, the comments on Question 7 and its subcomponents were intended
to provide input for the SDT in the development of its implementation plan to accompany
the project as it moves forward. The most frequently cited challenges – training,
agreements, and technical details – will be considered by the SDT.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 315-439-1390 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments on Generator Requirements at the Transmission Interface —
Project 2010-07
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
a.
b.
c.
d.
e.
f.
g.
8.
Do you agree that there is a reliability-related need for the proposed
standards action? ............................................................................................. 9
Do you agree with the scope of the proposed standards action? .................... 15
Do you agree with the proposed NERC Glossary additions or revisions? If you
disagree with one or more of the proposed new or modified definitions, please
provide a revision that would make the definition acceptable to you. ............ 22
Do you agree with the proposed new requirements intended to add clarity
around expectations for generator owners and operators at the transmission
interface? ....................................................................................................... 30
Do you agree with the proposed modified requirements intended to add clarity
around expectations for generator owners and operators at the transmission
interface? ....................................................................................................... 39
Do you believe there are any other Transmission Owner or Transmission
Operator standards or requirements that should be applicable to the
Generator Owner or Generator Operator other than those identified? ............ 51
The next posting of the proposed revisions to these standards will include
conforming changes to the measures and compliance elements, and will
include an implementation plan. Please identify how much time you feel an
entity will need to become fully compliant with the following new/revised
requirements: ................................................................................................. 54
Each Generator Operator shall provide its operating personnel with the
responsibility and authority to implement real-time actions to ensure the
stable and reliable operation of the Generation Facility and the Generation
Interconnection Facility, and to implement directives of the Transmission
Operator and Balancing Authority. (PER-001) ................................................ 58
Each Generator Operator shall implement an initial and continuing training
program for all personnel responsible for operating the Generator
Interconnection Facility to ensure the ability to operate the equipment in a
reliable manner. (Per-002) ............................................................................. 61
The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it
interconnects to preserve Interconnection reliability. (TOP-001) .................. 64
The Transmission Operator has decision-making authority for the Generator
Interconnection Operational Interface. (TOP-001) ......................................... 67
The Generator Operator shall notify the Transmission Operator of a change in
status of the Generation Interconnection Facility. .......................................... 70
The Generator Operator shall operate the Generation Interconnection Facility
within Facility Ratings. (TOP-004).................................................................. 73
The Generator Operator shall disconnect the Generation Interconnection
Facility immediately in coordination with the Transmission Operator when
time permits or as soon as practical thereafter if an overload or other
abnormal condition threatens equipment or personnel safety. (TOP-008) ..... 76
If you have any other comments on this SAR or proposed standard revisions
and NERC Glossary modifications that you have not already provided in
response to the prior questions, please provide them here. ........................... 79
2
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Philip R. Kleckley
SERC Planning Standards Subcommittee
Additional Member
X
Additional Organization
2
3
4
X
5
6
7
Region
Ameren Services Company
SERC
1
Entergy
SERC
1
3. James Manning
North Carolina Electric Membership Corporation
SERC
3
4. Pat Huntley
SERC Reliability Corporation
SERC
10
5. Bob Jones
Southern Company Services, Inc. - Transmission
SERC
1
Guy Zito
Additional Member
10
Segment Selection
2. Charles Long
Group
9
X
1. John Sullivan
2.
8
Northeast Power Coordinating Council
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Kurtis Chong
Independent Electricity System Operator
NPCC
2
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc.
NPCC
1
3
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
7. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
8. Ben Eng
New York Power Authority
NPCC
4
9. Brian Evans-Mongeon
Utility Services
NPCC
8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
12. Kathleen Goodman
ISO - New England
NPCC
2
13. David Kiguel
Hydro One Networks Inc.
NPCC
1
14. Michael R. Lombardi
Northeast Utilities
NPCC
1
15. Randy MacDonald
New Brunswick System Operator
NPCC
2
16. Greg Mason
Dynegy Generation
NPCC
5
17. Bruce Metruck
New York Power Authority
NPCC
6
18. Chris Orzel
FPL Energy/NextEra Energy
NPCC
5
19. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
20. Robert Pellegrini
The United Illuminating Company
NPCC
1
21. Saurabh Saksena
National Grid
NPCC
1
22. Michael Schiavone
National Grid
NPCC
1
23. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
3.
Group
Rick Terrill
Luminant
4.
Group
Jalal Babik
Electric Market Policy
Additional Member
X
X
Additional Organization
X
Region
Segment Selection
5
2. Mike Garton
NPCC
6
Ben Li
ISO RTO Council Standards Review
Committee
Additional Member
10
X
SERC
Group
9
X
1. Louis Slade
5.
8
X
Additional Organization
Region
Segment Selection
1. Patrick Brown
PJM
RFC
2
2. Jame Castle
NYISO
NPCC
2
4
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
3. Lourdes Estrada-Salinero
CAISO
WECC
2
4. Matt Goldberg
ISO NE
NPCC
2
5. Steve Myers
ERCOT
ERCOT
2
6. Bill Phillips
MISO
RFC
2
7. Mark Thompson
AESO
WECC
2
8. Charles Yeung
SPP
SPP
2
6.
Group
Jason L. Marshall
Midwest ISO Standards Collaborators
Additional Member
8
Additional Organization
Region
Segment Selection
CWLP
SERC
1
2. Jim Cyrulewski
JDRJC Associates, LLC
RFC
8
3. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
4. Barb Kedrowski
We Energies
RFC
3, 4, 5
5. Sam Ciccone
First Energy
RFC
1, 3, 4, 5, 6
6. Doug Hohlbaugh
First Energy
RFC
1, 3, 4, 5, 6
Group
Frank Gaffney
Additional Member
Florida Municipal Power Agency
X
Additional Organization
X
X
X
X
Region
Segment Selection
1.
City of Vero Beach
FRCC
3
2.
City of New Smyrna Beach
FRCC
3
3.
Kissimmee Utility Authority
FRCC
3
4.
Lakeland Electric
FRCC
3
5.
City of Clewiston
FRCC
3
6.
Beaches Energy Services
FRCC
1
7.
Fort Pierce Utility Authority
FRCC
4
8.
Group
Denise Koehn
Additional Member
1. Jim Burns
Bonneville Power Administration
X
Additional Organization
BPA, Transmission Technical Operations
10
X
1. Steve Rose
7.
9
X
X
X
Region
WECC
Segment Selection
1
5
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
9.
Group
Richard Kafka
Pepco Holdings, Inc - Affiliates
Additional Member
X
Additional Organization
2
3
4
X
5
6
X
X
7
Region
Conectiv Energy Supply, Inc
RFC
5
2. Don Bridge
Conectiv Energy Supply, Inc
RFC
5
3. James Newton
Pepco Energy Services
RFC
5
Group
Mary Jo Cooper
First Wind
Additional Member
Additional Organization
Region
Segment Selection
NPCC
5
2. Canandaigua Power Partners, LLC
NPCC
5
3. Canandiagu Power Partners II, LLC
NPCC
5
4. Milford Wind Coordior Phase I, LLC
WECC
5
5. Stetson Wind II, LLC
NPCC
5
6. Evergreen Wind Power V, LLC
NPCC
5
Group
Kenneth D. Brown
PSEG Companies
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Jim Hebson
PSEG ER&T
NPCC
6
2. Dave Murray
PSEG Fossil
ERCOT
5
3. Jim Hubertus
PSE&G
RFC
1, 3
12.
Group
Michael Gammon
Kansas City Power & Light
Additional Member
10
X
1. First Wind O&M, LLC
11.
9
Segment Selection
1. Kara Dundas
10.
8
X
Additional Organization
X
Region
X
X
Segment Selection
1. Jim Useldinger
KCPL
SPP
1, 3, 5, 6
2. Jennifer Flandermeyer
KCPL
SPP
1, 3, 5, 6
3. Nick McCarty
KCPL
SPP
1, 3, 5, 6
4. Melinda Mangold
KCPL
SPP
1, 3, 5, 6
5. Dennis Greashaber
KCPL
SPP
1, 3, 5, 6
6. Jerry Hatfield
KCPL
SPP
1, 3, 5, 6
6
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
7. Tom Saitta
KCPL
SPP
1, 3, 5, 6
8. Harold Wyble
KCPL
SPP
1, 3, 5, 6
13.
Individual
Jack Cashin
Energy Standards Working Group
14.
Individual
Brent Ingebrigtson
E.ON U.S.
X
X
X
X
15.
Individual
Silvia Parada-Mitchell
Transmission Owner/Generation Owner
X
X
X
X
16.
Individual
Larry Rodriguez
Entegra Power Group LLC
X
X
Individual
Ken Parker
Entegra Power Group LLC, i.e., Gila River
Power and Union Power Partners
18.
Individual
Jack Stamper
Public Utility District #1 of Clark County
19.
Individual
Daniel E. Kujala
Detroit Edison Company
20.
Individual
Mark Bennett
Competitive Power Ventures, Inc.
X
21.
Individual
Sam Dwyer
AmerenUE, Power Operations Services
X
22.
Individual
Amir Hammad
Constellation Power Source Generation Inc.
X
23.
Individual
Alisha Anker
Prairie Power, Inc.
24.
Individual
Michelle D'Antuono
Ingleside Cogeneration, LP
X
25.
Individual
Katy Mirr
Sempra Generation
X
26.
Individual
Robert Ellis
Mesquite Power
X
27.
Individual
Jon Kapitz
Xcel Energy
X
17.
8
9
X
X
X
X
X
X
X
X
X
7
10
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Commenter
Organization
Industry Segment
1
2
3
4
5
6
28.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
29.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
30.
Individual
Scott Helyer
Tenaska, Inc.
X
31.
Individual
Kevin Gillespie
El Dorado Energy LLC
X
Individual
Patti Metro
National Rural Electric Cooperative
Association (NRECA)
33.
Individual
Greg Rowland
Duke Energy
X
X
X
X
34.
Individual
James H. Sorrels, Jr.
American Electric Power
X
X
X
X
Individual
James Manning, Bob Beadle,
Doug White, and Richard McCall
North Carolina Electric Membership
Corporation
36.
Individual
Dan Rochester
Independent Electricity System Operator
37.
Individual
Jason Shaver
American Transmission Company
38.
Individual
Laura Zotter
ERCOT ISO
39.
Individual
Darcy O'Connell
California ISO
40.
Individual
Alice Murdock
Xcel Energy
X
X
X
X
41.
Individual
Marcus Lotto
Southern California Edison co.
X
X
X
X
32.
35.
X
X
7
8
9
10
X
X
X
X
X
X
X
8
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
1. Do you agree that there is a reliability-related need for the proposed standards action?
Summary Consideration: The overwhelming majority of stakeholder comments affirmed the need for this proposed standard action.
Organization
Yes or
No
E.ON U.S.
No
Question 1 Comment
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need for
auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Luminant
No
In general, Luminant agrees there is a need to address generation facilities with extended connections to the transmission
system. However, Luminant does not agree there is a reliability need for the proposed standards action as it relates to
generators connected in close proximity to the grid where the connection typically consists of a bus or short wires connection
from the high side of a generator step up transformer to the generator breaker.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Kansas City
Power & Light
No
There is a need to bring clarity to the Reliability Standards regarding the delineation of what the Generator Owner and
Generator Operator is responsible for and for definitions distinguishing between Generator Operators at Power Plants and
“Generator Operator” as the “Power System Operator” directing a fleet of generators in a balancing area. I do not believe
reliability of the interconnected grid has suffered as a result of the shortcomings of the Reliability Standards in this regard as
the electric industry has continued to operate in a responsible manner.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR. And while we respect your concern about the definition of Generator Operator versus Power System Operator, we maintain that it is outside the
scope of this SAR.
Detroit Edison
Company
No
Vegetation Inspectionchange to include any BES componentTransmission Line or Generator Interconnection Facility Rightof-Way or any other BES component to document vegetation conditions.
Response: Thank you for your comment. Based on the SAR DT’s interpretation of this comment, we believe it is outside the scope of the SAR.
9
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
AmerenUE, Power
Operations
Services
Yes
American Electric
Power
Yes
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
California ISO
Yes
Duke Energy
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
ERCOT ISO
Yes
First Wind
Yes
Question 1 Comment
10
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Florida Municipal
Power Agency
Yes
Independent
Electricity System
Operator
Yes
ISO RTO Council
Standards Review
Committee
Yes
Mesquite Power
Yes
Midwest ISO
Standards
Collaborators
Yes
National Rural
Electric
Cooperative
Association
(NRECA)
Yes
North Carolina
Electric
Membership
Corporation
Yes
Prairie Power, Inc.
Yes
PSEG Companies
Yes
Public Utility
District #1 of Clark
Yes
Question 1 Comment
11
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 1 Comment
County
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
South Carolina
Electric and Gas
Yes
Southern
California Edison
co.
Yes
Xcel Energy
Yes
Xcel Energy
Yes
Entegra Power
Group LLC
Yes
But, that action should be reasonable, provide specific detail, and be kept simple so the reliability-related objectives are
effectively understood by those operators of the GI Facilities.
Response: The SAR DT thanks you for your comment.
Energy Standards
Working Group
Yes
EPSA members, through active participation in many NERC activities including the team that prepared the report and the
attached SAR, are strong advocates of mandatory standards to protect reliability of the Grid. We also strongly agree that
there is a need for greater clarity of the responsibilities of Generator Owner/Operators and Transmission Owner/Operators at
the Generator Interconnection Interface and thus concur with the direction of this SAR that this should be achieved without
the need for Generator Owner/Operators to be included in the registry as Transmission Owner/Operators.
Response: The SAR DT thanks you for your comment.
Competitive Power
Yes
In fact, the technical analysis in the Ad Hoc Group's Report provides a valuable and useful understanding of the specific
nature and extent of reliability issues associated with generator interconnection facilities. Up to now, the need for generator
12
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Ventures, Inc.
Question 1 Comment
TO/TOP registrations has not been supported by a clear and technically sound rationale. The Report's conclusion, based
upon its comprehensive and thorough review, that there is no need for generators to be registered as TO/TOPs to address
the specific reliability issues is especially significant.
Response: The SAR DT thanks you for your comment.
Ingleside
Cogeneration, LP
Yes
Ingleside Cogeneration, LP believes that the effort by the Ad Hoc Group for Generator Requirements at the Transmission
Interface has generally succeeded in developing criteria clarifying the ownership and operational responsibilities of registered
generation and transmission entities at their point of interface. This is an important body of work which needs to result in an
end to the forced registration of Generator Owners/Operators (GO/GOP) as Transmission Owner/Operators (TO/TOP) by
Regional Entities.
Response: The SAR DT thanks you for your comment.
Pepco Holdings,
Inc - Affiliates
Yes
It is difficult to say if there is a “reliability-related need”. Most GOs operate and maintain their Generator Interconnection
Facility in the same manner as the rest of their generation facilities. It is beneficial to differentiate between the “Generation
Interconnection Facility” and the “Transmission” system so that GOs do not have to be registered as TOs.
Response: The SAR DT thanks you for your comment.
Tenaska, Inc.
Yes
Tenaska actively participates in many NERC activities, including the team that prepared the report and the attached
SAR/Draft Standards, and strongly advocates the need for reliability of the system. We also strongly agree that there is a
need for greater clarity of the responsibilities of Generator Owner/Operators and Transmission Owner/Operators at the
Generator Interconnection Interface and thus concur with the direction of this SAR that this should be achieved without the
need for Generator Owner/Operators to be included in the registry as Transmission Owner/Operators.
Response: The SAR DT thanks you for your comment.
Manitoba Hydro
Yes
With the implementation of the new Glossary Terms, this will clarify the dividing point between GO and TO.
Response: The SAR DT thanks you for your comment.
Constellation
Power Source
Yes
Yes - Defining the compliance responsibility to align more accurately with operational reality is important in managing
reliability. However, the SDT must also consider those entities that enter into a Joint Registration Organization (“JRO”) for
certain GOP reliability standards. This registration exception applies to market entities, where there has been a JRO created
13
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Generation Inc.
Yes or
No
Question 1 Comment
that delineates specific joint responsibilities, with respect to the GOP reliability standards. It is incumbent on both parties to
comply with their agreed upon respective responsibility.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT for their consideration.
14
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
2. Do you agree with the scope of the proposed standards action?
Summary Consideration: While there were a number of responses that indicated the SAR was too broad, an in-depth review of the
comments indicated that most of the concerns could be addressed by modifications to the proposed standards changes included in the Ad Hoc
Report. As a result, many of these comments will be referred to the SDT for their consideration, including final resolution of which standards need
to be modified. Based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings, the SAR
DT also elected to give the SDT the flexibility to include additional standards (now listed in the modified SAR) not identified in the Ad Hoc Report.
Organization
Yes
or No
American Electric
Power
No
Luminant
No
Question 2 Comment
Luminant believes the scope of the standards action significantly exceeds the reliability need. The scope should only extend to
Generation Interconnection Facilities of greater than one-half (½) mile in length from the property boundary of the generation
plant. This standards action should only be applied where there is a demonstrated reliability benefit. For the bulk of the
Generator Owners, the proposal creates excessive documentation and paperwork, and increases compliance risk with no
reliability benefit to the Bulk Electric System (BES).
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
California ISO
No
Adding language in several standards actually creates confusion rather than provide clarity. For example, EOP-003-1 (Load
Shedding Plans) applies in situations when there is insufficient generation or transmission, requiring load shedding to avoid risk
of uncontrolled failure of the interconnection. This function is generally accomplished through under frequency relay settings
which will drop a pre-determined amount of load to maintain generation/load balance. Involving the Generator Operator to
comply with this standard is unnecessary and may even complicate matters because the BA and the TOP will now have to
coordinate with GOPs. Other similar examples are EOP-001-0, EOP-004-1, and TOP-001-1 where adding “Generator
Interconnection Facility” does not add clarity but is rather redundant, and may create interpretation issues.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Public Utility
District #1 of Clark
No
Clark Public Utilities believes the scope of the proposed standards actions is too broad.
15
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
County
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need for
auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate.
Florida Municipal
Power Agency
No
FAC-003 should not be applicable to Generator Owners / Operators. The intent of all of the standards is to avoid an Adverse
Reliability Impact, or as the FPA Section 215(a)(4) defines “reliable operations” as: “operating the elements of the bulk-power
system within equipment and electric system thermal, voltage and stability limits so that instability, uncontrolled separation, or
cascading failures of such systems will not occur as a result of a sudden disturbance, including a cybersecurity incident, or
unanticipated failure of system elements.” Radial Facilities serving only generating plants when tripped will not threaten an
Adverse Reliability Impact or we would be hard pressed to run that generation in the first place.FMPA believes the intent of the
standard is to prevent a cascading event where, if a line trips, another line loads heavily increasing the sag of that line, which
may sag into un-cleared vegetation, causing the second line to trip, which may in turn cause heavily loading on a third line, etc.
If a line trips in the transmission network, radial Facilities from generating plants will not have their loading changed much at all
(since they are radial) and will not participate in this sort of “thermal” cascading event. Hence, there is no cause to regulate
vegetation management of radial Facilities to generating plants since the system is always planned and operated to that
potential contingency anyway and there is no danger of an Adverse Reliability Impact. Regulating vegetation management on
radial Facilities is beyond the scope of the Federal Power Act Section 215.Generator Owners / Operators are still incented to
perform adequate vegetation management without the need for regulation because any outage of the plant results in lost
opportunity costs to the plant.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Ingleside
Cogeneration, LP
No
No. Ingleside Cogeneration, LP believes there is a secondary, but equally important issue which we believe has not been fully
addressed in the proposed SAR. There can be components of the Generator Interconnection Facility located on the Generator
Owner’s property, but are maintained by the Transmission Owner. An excellent example is the relays protecting the
interconnected transmission line. Although these are usually purchased by the Generator Owner and are financially carried on
their books, in some cases the Transmission Owner performs the associated maintenance and testing. This arrangement can
16
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
make sense as the relays are protecting a transmission system and must properly interact with relays on the other side of the
transmission line through associated communications systems. This kind of arrangement can lead to a variety of interpretations
by auditors even when presented with an Interconnection Agreement specifying the ownership/maintenance arrangement. We
believe that if the responsibility to a requirement is clearly delineated in a formal document, the associated collection and
presentation of evidence of compliance is part of that responsibility - in this case the TO owning maintenance and testing of
protective relays financially owned by the GO.The Exclusion statement under Section III.c.4 of the Statement of Compliance
Registry Criteria allows for compliance responsibility to be transferred to another entity provided it registers as the appropriate
entity. In addition, we recognize that Sections 501 and 507 of the NERC Rules of Procedure allows distribution of responsibility
among two or more entities through a Joint Registration - although that process is designed for tightly connected organizations
such as joint ventures or cooperatives.
We recommend these all-or-nothing approaches be modified in the exclusion as suggested below:
A generator owner/operator will not be registered based on these criteria if responsibilities for compliance with approved
NERC reliability standards or associated requirements including reporting have been transferred by written agreement to
another entity that has registered for the appropriate function for the transferred responsibilities, such as a load-serving
entity, G&T cooperative or joint action agency as described in Sections 501 and 507 of the NERC Rules of Procedure.
"Responsibility for individual requirements applicable to the Generator Interconnection Facility including reporting can be
transferred by written agreement without a change to an entity’s registration."
Response: The SAR DT thanks you for your comment. It is outside the scope of both the SAR DT and the SDT to propose changes to the NERC Rules of
Procedure.
ISO RTO Council
Standards Review
Committee
No
Please see our comments under Q8.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
Constellation
Power Source
Generation Inc.
No
Please see the comments for Question #4: Constellation agrees with the proposed new requirements in principal. However,
further clarity is needed in the requirements so that there isn’t any added confusion. Either an implementation plan or a
“frequently asked questions” document would be recommended.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
17
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Prairie Power, Inc.
No
Question 2 Comment
PPI believes the group has extended the scope too broadly from its initial intent as described in comments below.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions
proposed in this SAR are appropriate. Specific modifications will be determined by the SDT.
AmerenUE,
Power Operations
Services
No
While we agree with the overall scope of the proposed actions, there appears to be one missing critical element. What
requirement will ensure that each GO, GOP, TO and TOP agree on the specifics of implementing these new requirements for
each GIF? Has the Ad Hoc Group considered adding a requirement to mandate execution of an Agreement or Procedure
between the GO, GOP, TO and TOP to ensure minimal specific actions that would guarantee compliance with each GIF
Requirement?
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard
or an existing standard(s).
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
Competitive
Power Ventures,
Inc.
Yes
Detroit Edison
Company
Yes
Duke Energy
Yes
El Dorado Energy
LLC
Yes
Electric Market
Yes
18
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
Policy
Energy Standards
Working Group
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
ERCOT ISO
Yes
Independent
Electricity System
Operator
Yes
Kansas City
Power & Light
Yes
Manitoba Hydro
Yes
Mesquite Power
Yes
Midwest ISO
Standards
Collaborators
Yes
North Carolina
Electric
Membership
Corporation
Yes
PSEG Companies
Yes
19
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
South Carolina
Electric and Gas
Yes
Southern
California Edison
co.
Yes
Tenaska, Inc.
Yes
Entegra Power
Group LLC
Yes
Question 2 Comment
BUT, FAC-003 SHOULD BE APPLIED IN A REASONABLE MANNER. MORE DETAIL SHOULD BE PROVIDED THAN IT
WOULD APPLY FOR MORE THAN 2 SPANS. WHAT IF THERE ARE 3 SPANS, BUT ONLY A QUARTER MILE IN DISTANCE
WHICH IS TOTALLY VISIBLE FROM THE GIF. THE SDT SHOULD MAKE SOME REASONABLE CONCESSIONS FOR
THESE SITUATIONS, OR ALLOW THE GIF TO DOCUMENT THE SOUND REASONING USED IN NOT IMPLEMENTING
FAC-003 TO THE EXTENT REQUIRED BY THE EXISTING STANDARD. A REASONABLE VEGETATION MANAGEMENT
PROGRAM SHOULD BE ADEQUATE. MORE DETAIL AND SPECIFICS DESCRIBING WHAT ADEQUATE TRAINING IS FOR
PER-002.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Pepco Holdings,
Inc - Affiliates
Yes
Defining “Generator Interconnection Facility” in the glossary is a good idea. Going beyond this to specifically note this term in
so many other standards seems unnecessary since other individual devices are not noted in so many other locations. If
“Generator Interconnection Facility” is included in all other Generating Facilities, this may simplify the process.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
Yes
The proposed SAR modification set is the responsible approach to resolve gaps Generator Interconnection Facility gaps
identified by the industry. The functions required of an Owner(s) and Operator(s) of facilities used to connect generation to the
20
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes
or No
Question 2 Comment
BES (Generator Interconnection Facilities) are not the same as the functions required to own and operate Transmission and
should not be considered to be the same. We commend the task force for coming up with a reasonable approach that directly
addresses reliability without requiring GO and GOPs to perform activities that have no bearing on the reliability of the BES.
Response: The SAR DT thanks you for your comment.
21
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
3. Do you agree with the proposed NERC Glossary additions or revisions? If you disagree with one or more of the
proposed new or modified definitions, please provide a revision that would make the definition acceptable to
you.
Summary Consideration: While a majority of comments did not challenge the need for the proposed new definitions, some did suggest
modifications to those new terms, as well as to some existing terms defined in the NERC Glossary of Terms. Given this, the SAR DT modified the
SAR to make it clearer that the SDT can adopt proposals as indicated in the report or modify them to address stakeholder concerns expressed in
responses to the SAR DT questionnaire.
Organization
Yes or No
Xcel Energy
Question 3 Comment
Should the definition of Generator Interface Facility indicate that no BES (or any) loads be tapped between the generator
and the GIF operational interface?
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Independent
Electricity System
Operator
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator Operator, but do not agree with the
need for the second sentence. The first sentence already states inclusion of Generator Interconnection Facility. The first
part of the second is simply a repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence. (2) Generator Interconnection
Facility: The Sole-use facilities should include those which transmit power to redial customer loads if such facilities do not
form a part of the connection to multiple transmission facilities that are subject to network power flows.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
ISO RTO Council
Standards Review
Committee
No
(1) Generator Operator: We agree with the first sentence of the definition for Generator Operator, but do not agree with the
need for the second sentence. The first sentence already states inclusion of Generator Interconnection Facility. The first
part of the second is simply a repeat of this change. The latter part of the second sentence is a requirement that should be
stipulated in an appropriate standard. We suggest to strike out the second sentence.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Duke Energy
No
o The definitions of Generator Owner and Generator Operator should not be revised, because every Generator Owner
and Generator Operator may not own and operate a Generator Interconnection Facility, as the revised definitions imply.
The revised definition of Generator Operator also adds a coordination requirement which is more properly included in the
requirements of a standard.
o While we are sensitive to the fact that this SAR is attempting to close a reliability gap, we believe that the definition of
22
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
Generator Interconnection Facility is too broad. The Standard Drafting Team should consider limiting it to the voltages
defined for the Bulk Electric System, and other facilities as deemed critical by the Regional Entity. Also, how does the
Regional Entity deem a facility “critical”?
o The Right-of-Way (ROW) definition should spell out TO and GO. Suggested rewording: “A corridor of land on which
electric lines may be located. The Transmission Owner or Generator Owner which owns the lines may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to construct and maintain the lines.”
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Public Utility
District #1 of Clark
County
No
Clark Public Utilities believes the proposed definitions do not provide the necessary amount of guidance and clarity. The
proposed definitions and standards revisions are being considered because of the potential impacts of a 26-mile 500 kV
Generation Interconnection Facility. The proposed definition for the term “Generation Interconnection Facility” will include
the 26- mile interconnection as well as a host of other types of interconnections that should not be considered in this effort.
Clark’s generator is attached to the transmission grid by slack span (less than 100’) between the high side of the GSU
(owned by the generator)and a circuit breaker (owned and operated by the Transmission Operator) located within the
Transmission Operators switchstation. There are no operable components in the slack span. Clark believes the currently
proposed standards actions are overly broad. The definitions and applicability of these standards must be narrowed.
Clark proposes the following definition for Generator Interconnection Facility.Generator Interconnection FacilitySole-use
facility for the purpose of connecting the generating unit(s) to the transmission grid In this regard, the sole-use facility only
transmits power associated with the interconnecting generator, whether delivered to the grid or delivered to the generator
for station service or auxiliary load, or delivered to meet cogeneration load requirements. Generator Interconnection
Facilities shall not include lines that are less than or equal to two spans in length or lines that the host Transmission
Operator has agreed to include as part of the transmission system it operates.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Kansas City
Power & Light
No
I believe the intent of what has been proposed here is to define the term, “Generator Operator” to mean the Operator that
operates units directly at a power station. With that in mind, although the proposed definition is close, I believe the
interaction with the Transmission Operator only in the definition makes this confusing. Recommend consideration of the
following definition:The entity that operates generating unit(s) and the Generator Interconnection Facility and performs the
functions of supplying energy and reactive power as directed by the Balancing Authority and the Transmission Operator.
The Generator Operator may also operate the Generator Interconnection Facility and is responsible for coordinating with
the Balancing Authority and the Transmission Operator when the facility is energized or about to be energized to/deenergized from the transmission system.In addition, recommend adding the generating station property line to the defintion
for Generator Interconnection Facility for clarity:Sole-use facility that leaves generator property line for the purpose of
connecting the generating unit(s) to the transmission grid. In this regard, the sole-use facility only transmits power
23
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
associated with the interconnecting generator, whether delivered to the grid or delivered to the generator for station service
or auxiliary load, or delivered to meet cogeneration load requirements.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Electric
Power
No
It is unclear if the Generator Interconnection Facility definition only includes facilities at 100 kV or greater or those deemed
critical to the Bulk Electric System by the Regional Entity.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina
Electric
Membership
Corporation
No
NCEMC seeks clarification from the ad hoc team regarding the definition of Generation Interconnection Facility (GIF),
especially regarding the option for ownership of the GIF. The way the definition currently reads leaves the interpretation
that it might be optional for the Generator Operator to own the GIF. We are not sure that the Ad Hoc team intended this
possible conclusion, which in our opinion, could completely change the scope of this SAR (in the case where the GOP
does NOT own the GIF). If that is the intent of the Ad Hoc team or SDT, then the definition of Generator Operator should
be changed to reflect the "option" of the GOP owning the GIF versus someone else like the Transmission Owner/Operator.
Also, the second sentence of the GOP definition is not needed in our opinion since it is a requirement of the standards and
as such requirements are not usually a part of the NERC definition.
Other definitions we suggest changing are as follows:Vegetation Inspection - The systematic examination of a Right-ofWay to document vegetation conditions. The main reason for the change in definition for ROW was the proposed use of
the non-capitalized term "electric line". Since the use of that phrase sometimes means distribution lines as well as
transmission, we suggest staying with the capitalized NERC terms for better clarity.Right-of-Way (ROW) - A corridor of
land on which a Transmission Line or Generator Interconnection Facility may be located. The owner of the Transmission
Line or Generator Interconnection Facility may own the land in fee, own an easement, or have certain
franchise,prescription, or license rights to construct and maintain lines.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI agrees with the first and existing sentence of the Generator Operator definition. However, the first part of the second
sentence regarding operating the Generator Interconnection Facility is redundant with the first sentence. The second
portion of the second sentence regarding coordinating with the Transmission Operator has been established already in
TOP-001 R7.1 and TOP-003 R1.1 for the purpose of this project.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
24
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
California ISO
No
Question 3 Comment
The definition for “Generator Interconnection Facility” (GIF) is not consistent with either Conclusion #1 of the Adhoc
Group’s final report, or with “Applicability 4.5” added under FAC-003-1. Conclusion #1 mentions “Generator
Interconnecting Facilities operating at a voltage of 100 kV or greater or those deemed critical to the Bulk Electric System
by the Regional Entity...” and Applicability 4.5 mentions “Generator Interconnection Facility above 200 kV... or are
otherwise deemed critical by the Regional entity below 200 kV...”. In both these instances it appears that the Adhoc Group
is emphasizing those Generator Interconnection Facilities that are either part of the Bulk Electric System (BES) or deemed
critical by the Regional entity. Therefore, we suggest modifying the definition as follows:First sentence, after the word grid,
add “above 200 kV or otherwise deemed critical by the Regional entity below 200 kV”.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Manitoba Hydro
No
The definition for Generator Interconnection Facility does not fully include the recommendations of the Ad Hoc Group
Conclusions. The first conclusion states that the facility must be 100 KV and above and more importantly that if there is
power flows through this station that do not belong to the generators or their exclusive station loads, then this station
becomes a TO responsibility.The definition of Transmission somewhat covers the above statement, but still need
clarity.Example:Transmission - An interconnected group of lines and associated equipment in which network powerflows
through this station are associated with the movement or transfer of electric energy between points of supply and points at
which it is transformed for delivery to customers or is delivered to other electric systems. Generator Interconnection Facility
will not contain any of the above criteria.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation
Power Source
Generation Inc.
No
The term “point of interconnection” must be used in the glossary definitions of a “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface.” It is a common industry term that is widely understood, and is even
being used in the revision to FAC-008. Using the term “point of interconnection” would further clarify the new glossary
definitions. Here are the proposed changes:Generator Interconnection Facility (NEW)Sole-use facility for the purpose of
connecting the generating unit(s) to the transmission grid. In this regard, the sole-use facility only transmits power
associated with the interconnecting generator, whether delivered to the grid or delivered to the generator for station service
or auxiliary load, or delivered to meet cogeneration load requirements.The Generator Interconnection Facility is physically
defined as the facility and its encompassing equipment beginning at the low side of the Generator Step Up to the point of
interconnection. Generators connected to the same interconnection facility with different Generator Operators must
coordinate operations. Generator Interconnection Operational Interface (NEW)Location at which operating responsibility
for the Generator Interconnection Facility changes between the Transmission Operator and the Generator Operator.This
location is known as the point of interconnection.
Response: The SAR DT thanks you for your comment. Because of potential confusion with language in various interconnection agreements, the SAR DT will
25
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
not make changes to this definition and will defer to the SDT.
Midwest ISO
Standards
Collaborators
No
We agree with the first sentence of the definition of Generator Operator. However, the first part of the second sentence
regarding operating the Generator Interconnection Facility is redundant with the first sentence. The second portion of the
second sentence regarding coordinating with the Transmission Operator is a requirement and already established in
requirement X.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
No
We recommend the definition of Generator Interconnection Facility be modified.
”Generator Interconnection Facility (NEW)A facility used for the sole purpose of connecting the generating unit(s) to
the transmission grid. In this regard, the sole-use facility only transmits power associated with the interconnecting
generator(s), whether delivered to the grid or delivered to the generator(s) for station service or auxiliary load, or
delivered to meet cogeneration load requirements.
The purpose of the above modification is to account for the situations where a Generator Operator may have many units,
such as wind turbines, all using the same Generator Interconnection Facility to connect to the transmission grid.
Additionally, we feel it is irrelevant if the Generating Unit is owned by one or the same owners. Two scenarios explain why
multiple generators using the same Generator Interconnection Facility does not serve a function of a TO or TOP.
• Scenario 1Each Generator Operator is connected to the Transmission Operator through an independent Generator
Interconnection Facility. There is no need for the Generator Operators to coordinate their operations with one
another because their operations do not impact common facilities. However, there may be a need for the
Transmission Operator to coordinate its instructions to the Generator Operators (if they issue voltage schedules,
for example). When it becomes necessary for the Transmission Operator to communicate instructions to the
Generator Operators, it is necessary for the Transmission Operator to communicate with each of the Generator
Operators.
• Scenario 2Generator Operator A is connected independently, but Generator Operators B and C share a common
Generator Interconnection Facility. In this case, it is necessary for Generators B and C to coordinate their
operations. It is not necessary to designate either GO_B or GO_C as the “operator” of the Generator
Interconnections Facility. Rather, it is most appropriate to place the obligation to coordinate operations on both
parties. By placing the obligation on both parties, they share an equal burden to comply with the applicable
standards.Placing the obligation to coordinate operations on both GO_B and GO_C does not increase the burden
to the Transmission Operator.
If there is trouble at the point of interconnect substation, the Transmission Operator might need to coordinate operations
with GO_A, GO_B and GO_C in either Scenario 1 or Scenario 2. If in Scenario 2, the Transmission Operator only issued
26
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Question 3 Comment
instructions to GO_A and GO_B, they could not be sure that GO_C would receive the instructions. Furthermore, since
GO_B is not a Transmission Operator, they lack the authority to issue instructions to GO_C.
We recommend an additional requirement to resolve coordination between generators. For example “Generator Operators
interconnected through a common Generator Interconnection Facility shall coordinate their operations.”
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
SERC Planning
Standards
Subcommittee
No
We suggest 3 alternate modified definitions:
Right-of-Way (ROW)A corridor of land on which a Transmission Line or Generator Interconnection Facility may be located.
The owner of the Transmission Line or Generator Interconnection Facility may own the land in fee, own an easement, or
have certain franchise, prescription, or license rights to construct and maintain lines.
Vegetation InspectionThe systematic examination of a Right-of-Way to document vegetation conditions.The main reason
for the change in definition for ROW was the proposed use of the non-capitalized term "electric line". Since the use of that
phrase sometimes means distribution lines as well as transmission, we suggest staying with the capitalized NERC terms
for better clarity.
Generator OperatorThe entity that operates generating unit(s) and performs the functions of supplying energy and
Interconnected Operations Services. The Generator Operator may also operate the Generator Interconnection Facility.
The main reason for the change in the definition for Generator Operator was that the 2nd sentence in the proposed
definition was a requirement and not a true definition. The other change was to allow for the case where the Generator
Operator was not the operator of the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE,
Power Operations
Services
Yes
American
Transmission
Company
Yes
Bonneville Power
Administration
Yes
27
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Detroit Edison
Company
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
Florida Municipal
Power Agency
Yes
Ingleside
Cogeneration, LP
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra
Generation
Yes
South Carolina
Electric and Gas
Yes
Tenaska, Inc.
Yes
Question 3 Comment
28
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Pepco Holdings,
Inc - Affiliates
Yes
Question 3 Comment
“Generator Interconnection Facility” is useful to allow GOs to be distinguished from TOs and their responsibilities.
“Generator Interconnection Operational Interface” is also known as the “Point of Interconnect” by the RTO. This may be
an alternate name that could be used to make things standard.
Response: The SAR DT thanks you for your comment. Because of potential confusion with language in various interconnection agreements, the SAR DT will
not make changes to this definition and will defer to the SDT.
Southern
California Edison
co.
Yes
Additional clarification would be useful as it/ they would cut down on future requests for interpretation... i.e provide a
specific threshold for the proposed Generator interconnection Facility definition
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Energy Standards
Working Group
Yes
In particular we support the revised definition of the Generator Interconnection Facility, which has appropriately
incorporated our comments from the draft of the Team’s report
Response: The SAR DT thanks you for your comment.
29
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
4. Do you agree with the proposed new requirements intended to add clarity around expectations for generator
owners and operators at the transmission interface?
Summary Consideration: A number of responses expressed concern about the need for various proposed new requirements. An in-depth
review of the comments, however, indicated that most of the concerns could be addressed by the SDT. As a result, many of these comments will
be referred to the SDT for their consideration, including final resolution of which standards need to be modified. Revisions to the SAR also allow
the SDT the option of merging the changes into one new standard or an existing standard(s).
Organization
Kansas City Power &
Light
Yes or
No
No
Question 4 Comment
o PER-001, R1: The language proposed for PER-001, R1, infers the Generator Operator is able to take independent
actions regarding the “Generation Facility” and the Generator Interconnection Facility. There is no definition for
Generation Facility in this proposal or currently in the NERC Glossary. At any rate, do not agree with the Generator
Operator taking any independent actions other than those to monitor and maintain the safe operation of a generating
unit for the production of energy and reactive power.
o PER-002, R3 (Proposed here): This infers again the Generator Operator taking independent actions with regard to
equipment within the Generator Interconnection Facility. Although, the Generation Interconnection Facility is defined
properly, that does not mean the Generator Operator is the control authority over that equipment. It is not uncommon
for the Generator Operator to operate equipment within the Generator Interconnection Facility at the direction of the
Transmission Operator. Recommend consideration be given to modify this requirement to reflect that.
o TOP-001, R9 and R10 (Proposed here): This infers again the Generator Operator taking independent actions with
regard to equipment within the Generator Interconnection Facility. Although, the Generation Interconnection Facility is
defined properly, that does not mean the Generator Operator is the control authority over that equipment. It is not
uncommon for the Generator Operator to operate equipment within the Generator Interconnection Facility at the
direction of the Transmission Operator. Recommend consideration be given to modify these requirements to reflect the
Transmission Operator can be the authority over the equipment within the Generation Interconnection Facility but that
the Generator Operator may operate that equipment at the direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Electric Power
No
AEP believes that the only new requirement that should be addressed is in reference to FAC-003. AEP does not see
benefit in expanding the scope of EOP-003, PER-001, and PER-002.With respect to TOP-004, AEP does not feel the
added requirement is necessary as the Generator Interconnection Facility should be adequately sized to handle the
output of the generator. The added requirement in TOP-008 for notification is redundant with other obligations for the
GOP to notify other entities, such as in COM-002 and TOP-003.
30
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
American Transmission
Company
No
Clarify the definition of generator interconnection facility to include who this applies to as shown in the conclusions
above in #3. A Generator Interconnection Facility is considered as though part of the generating facility specifically for
purposes of applying Reliability Standards to a Generator Owner or Generator Operator.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the
need for auditable reliability standards to be added between the GO/TO. Also, it is not necessary to include the phrase
“including the Generator Interconnection Facility” in all the applicable requirements. Since the term Generator
Interconnection Facility is proposed to be included in the Glossary definitions for Generator Operator, then it would be
redundant to also add the phrase throughout the applicable standards.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Public Utility District #1
of Clark County
No
Many of the new requirements place excessive demands on generators that do not increase system reliability.
In EOP-003 Generator Operators are added to the applicability and as a result R7 is a newly applicable requirement to
Generator Operators. However, this requirement now implies that Generator Operators are required to engage in the
coordination efforts (with the BA and TOP) of automatic underfrequency load shedding. Generators do not have the
option of determining what levels of frequency to ride through and what levels of frequency to trip on. Those quantities
are defined by the RC and the BA and Generator Operators are required to have generator protection system settings
that allow this ride through. Generators should have frequency and voltage ride through requirements that are
coordinated with automatic load shedding programs by the RC, BA and/or TOP but should simply be required to
comply with these requirements and shoud not have a role in the coordination. The comments in the GOTO Final
report indicate that this addition is required to ensure that a generator frequency trip set point is appropriately included
in the currently required coordination between the BA and TOP. Clark believes that generators should not participate in
the coordination but simply be required to comply with frequency ride through requirements dictated by the RC, BA
and/or TOP.
Clark believes that FAC-002 clearly applies to Generator Owners and this standard requires that generator integration
facilities address reliability impacts in the interconnected transmission system. Additionally, the proposed change to
EOP-003 appears to have nothing to do with the issue at hand (i.e. removal of TOP status to a generator because of a
Generator Interconnection Facility).
Clark believes it is inappropriate to make EOP-003 applicable to Generator Operators and to imply that a Generator
31
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Operator has any participation in coordination of underfrequency load shedding other than to comply with frequency
ride through requirements of the RC, BA and/or TOP.
Clark agrees that the changes to FAC-003 are appropriate, will lead to increased reliability and do not result in
unnecessary reporting or paperwork. The applicability section clearly limits the scope of what Generation
Interconnection Facilities would be included in this standard by having a “two span” limit in the length of the facility.
This limit appropriately will exclude those generators that have arranged for a Transmission switchstation owned and
operated by a Transmission Operator located immediately adjacent to the generator.
In IRO-005, R13, the standard proposes to require a Generator Operator to immediately inform the TOP of status
changes to SPS. While Clark is not opposed to this change, it is unclear why the issue at hand (i.e. removal of TOP
status to a generator because of a Generator Interconnection Facility) has lead to this addition. The SAR implies that
the industry need leading to the SAR is the “registration of Generator Owners and Generator Operators as
Transmission Owners and Transmission Operators, based on the facilities that connect the generators to the
interconnected grid.” IRO-005, R13 does not appear to have any connection to this industry need.
In PER-001, Generator Operators are added to the applicability and as a result of the new R2 Generator Operators will
be required to demonstrate the authority of operating personnel over Generation Facilities and Generation
Interconnection Facilities. This level of authority is unnecessary. Transmission Operators already have this authority
(refer to PER-001, R1). Generator Operators are already required to comply with reliability directives issued by RCs,
BAs, and TOPs in other reliability standards. The requirement to demonstrate that a generator needs this authority
over its generating facility is unnecessary and has no connection with the industry need the SAR is based on. A
generator operator has authority over its generator by virtue of its registration as a Generator Operator. The need for
further proof that a GOP can operate generation facilities for which it is a registered GOP has not been demonstrated.
The requirement to demonstrate that a generator needs authority over a Generation Interconnection Facility is; for the
same reason, unnecessary. A generator operator has authority over its generator by virtue of its registration as a
Generator Operator for that facility. The need for further proof that a GOP can operate Generation Interconnection
Facilities for which it is a registered GOP has not been demonstrated.
In PER-002, Generator Operators are added to the applicability and as a result of the new R3 Generator Operators will
be required to demonstrate training programs similar to TOP training requirements. Clark is not opposed to training its
GOP personnel; however, including the training program within the PER-002 training requirements elevates this
training to a level that has not been demonstrated to be necessary in all cases. Currently, this requirement is
applicable to a TOP. By removing the TOP classification to certain GO/GOP registered entities that are only a TOP by
virtue of Generation Interconnection Facilities, the potential exists that inadequately trained personnel may be directing
the operation of a Generation Interconnection Facility. However, as stated earlier, when the Generation
Interconnection Facility is short in length and more importantly when this facility has no devices which can be operated
(i.e. direct connection between the generator step-up transformer or generator protection circuit breaker (owned or
32
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
operated by the GOP) and the TOP owned and operated transmission breaker) there is no gap in having adequately
trained personnel operating transmission facilities. Clark believes the applicability section should include minimal limits
for applicable Generation Interconnection Facilities or that the definition of Generation Interconnection Facilities should
be amended such that PER-002 applicability is limited to GOPs that own facilities that are similar in nature to the New
Harquahala Generation Interconnection Facilities that have led to this SAR.
The proposed changes to TOP-004 are confusing. The proposal does not add GOP in the applicability section but the
newly proposed R7 appears to obligate GOPs. The requirement should be revised to obligate a TOP to ensure that a
GOP operates within its applicable limits. These limits should have already been established.
In FAC-008 Transmission Owners and Generator Owners are required to have a ratings methodology.
In FAC-009 TOs and GOs are required to calculate facility ratings. In both of these standards, documentation is to be
made available to RCs, TOPs, PAs and TPs that have responsibility. At the very least, the applicability section of a
standard should be coordinated with the entities having obligations due to the requirements of a standard.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.)
Luminant
No
No, for the bulk of the Generator Owners whose Generation Interconnection Facilities (GIF) are connected in close
proximity (i.e., one-half mile or less) to the BES, the requirements will only add additional unduly burdensome
documentation, paperwork and compliance risk, with no reliability benefit
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Independent Electricity
System Operator
No
Please see our comments under Q5 where we comment on both the additions and modifications to the standards.
ISO RTO Council
Standards Review
Committee
No
Please see our comments under Q5 where we comment on both the additions and modifications to the standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI considers the phrase “for SPS relay or control equipment under its control” to be confusing and ambiguous in the
new requirement IRO-005 R13. We suggest deletion of this phrase maintains the intent of the requirement and
removes the unclear reference to the subject associated with the word “its”.
33
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
PPI questions why the sub-elements of new requirement TOP-001 R9 are stipulated in bullet item format rather than
sub-requirement format.
PPI agrees with the first portion of new requirement PER-001 R2. Regarding the second portion of new PER-001 R2,
the Generator Operator is already required to comply with Reliability Coordinator directives as established in IRO-001
R8 and TOP-001 R3, and further the Generator Operator is already required to comply with Transmission Operator
directives also as established in TOP-001 R3. PPI does not see any benefit in reiterating the Generator Operator
responsibility and authority to follow directives in this new requirement. PPI would suggest stipulating the Generator
Operator be responsible for following directives of the Balancing Authority in a separate Requirement or subrequirement, and not lumped into this new requirement.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT. The bulleted items in TOP001 R9 should have been numbered. We’ll pass this comment on to the SDT.
Duke Energy
No
See detailed comments under Question 5 below.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE, Power
Operations Services
No
See response to Item #2.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard or
an existing standard(s).
Midwest ISO Standards
Collaborators
No
The requirement additions to the TOP standards parallel requirements that the Real-Time Operations standards
drafting team has already proposed for removal. This project needs to be coordinated with the Real-Time Operations
project.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Tenaska, Inc.
No
TOP-001 R10 should be amended such that the proposed R10 reads as follows: The Transmission Operator shall have
decision-making authority over operation of the Generator Interconnection Operational Interface at all times in order to
preserve interconnection reliability, unless by exercising that authority such actions would violate safety, equipment,
regulatory or statutory requirements. Under these circumstances the Generator Operator shall immediately inform the
Reliability Coordinator or Transmission Operator of the inability to perform the directive so that the Reliability
34
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
Coordinator or Transmission Operator can implement alternate remedial actions.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina Electric
Membership Corporation
No
We agree with most of the new requirements with the exception of two:
1) New requirement R9 of TOP-001 appears to be very similar to existing requirements of TOP-001 (req R7) and TOP003 (req R1). Further clarification is needed to distinguish the differences between this new requirment and existing
requirements.
2) New requirement R5 of TOP-008 directs the GOP to disconnect the GIF when “safety is jeopardized” or... which
triggers the immediate question: Who’s safety does the Ad Hoc group refer to, the personnel of the GO/GOP or the
safety of the transmission system or its personnel or both possibly? Please clarify. If it the safety of the transmission, its
personnel or the system grid in general, then why would it not be the TOP's responsibility to provide a directive of this
nature since the TOP would have a greater perspective/visibility than the GO/GOP of the system operating conditions
in real time?
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Energy Standards
Working Group
No
We are supportive of most of the new requirements being suggested with the following two exceptions:
IRO-005 R13 which states:R13. The Generator Operator shall immediately inform the Transmission Operator of the
status ofthe Special Protection System, including any degradation or potential failure to operate as expected for SPS
relay or control equipment under its control.We believe that this proposed additional requirement is redundant as it is
already covered by the requirements of PRC-001-1
ANDTOP-001 R10 which states:The Transmission Operator shall have decision-making authority over operation of
theGenerator Interconnection Operational Interface at all times in order to preserveInterconnection reliability.
We would amend the proposed R10 as follows: The Transmission Operator shall have decision-making authority over
operation of the Generator Interconnection Operational Interface at all times in order to preserve interconnection
reliability, unless by exercising that authority such actions would violate safety, equipment, regulatory or statutory
requirements. Under these circumstances the Generator Operator shall immediately inform the Reliability Coordinator
or Transmission Operator of the inability to perform the directive so that the Reliability Coordinator or Transmission
Operator can implement alternate remedial actions.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
35
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Electric Market Policy
Yes or
No
No
Question 4 Comment
We feel it is not necessary to include the phrase “including the GeneratorInterconnection Facility” in all the applicable
requirements. The term Generator Interconnection Facility is proposed to be included in the Glossary definitions and
the proposed definition of Generator Operator includes the following language “also operates the Generator
Interconnection Facility and is responsible for coordinating with the Transmission Operator when the facility is
energized or about to be energized to/de-energized from the transmission system” which we feel is sufficient and
superior to having the phrase repeated throughout the applicable standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
First Wind
No
We feel it is not necessary to include the phrase “including the GeneratorInterconnection Facility” in all the applicable
requirements. The term Generator Interconnection Facility is proposed to be included in the Glossary definitions and
the proposed definition of Generator Operator includes the following language “also operates the Generator
Interconnection Facility and is responsible for coordinating with the Transmission Operator when the facility is
energized or about to be energized to/de-energized from the transmission system” which we feel is sufficient and
superior to having the phrase repeated throughout the applicable standards.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
California ISO
Yes
Competitive Power
Ventures, Inc.
Yes
El Dorado Energy LLC
Yes
Entegra Power Group
LLC, i.e., Gila River
Power and Union Power
Partners
Yes
Florida Municipal Power
Agency
Yes
Ingleside Cogeneration,
Yes
36
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
LP
Manitoba Hydro
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra Generation
Yes
SERC Planning
Standards Subcommittee
Yes
South Carolina Electric
and Gas
Yes
Southern California
Edison co.
Yes
Additional clarification would be useful as it/ they would cut down on future requests for interpretation.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc Affiliates
Yes
Application of FAC-003 for Gen Interconnect Facilities that are "two spans, generally 1/2 mile or more past the property
line" is reasonable as long as the "property line" remains in the definition. OK.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation Power
Source Generation Inc.
Yes
Constellation agrees with the proposed new requirements in principal. However, further clarity is needed in the
requirements so that there isn’t any added confusion. Either an implementation plan or a “frequently asked questions”
document would be recommended.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Bonneville Power
Administration
Yes
However, believe there is a problem with #8 referring to TOP-008. The solution to the generator facilitiy line overload
may be a transmission system problem so the Generatior should not disconnect unless the TOP directs it to do
37
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 4 Comment
so(confer unless a safety issue). Also, TOP-001 needs careful work. The transmision system doesn't want
environmental issues turning off generators during emergency or critical transmission conditions.
Entegra Power Group
LLC
Yes
SEE COMMENTS FOR QUESTION 2.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
38
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
5. Do you agree with the proposed modified requirements intended to add clarity around expectations for
generator owners and operators at the transmission interface?
Summary Consideration: A number of responses expressed concern about the proposed modifications. An in-depth review of the
comments indicated that most of the concerns could be addressed by the SDT during the standards drafting process. Based on discussions
with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings, the SAR DT modified the SAR to give the
SDT the flexibility to consider further modifications not identified in the Ad Hoc Report.
Organization
Independent
Electricity System
Operator
Yes or
No
Question 5 Comment
(1) We realize that the SDT needs to make changes to “approved standards” but there are a number of standards involved
in this project whose newer versions have either received the BoT approval, or about to be adopted by the BoT or at the
stage of being finalized or balloted. To make changes to the soon to be outdated versions is confusion and will require a
subsequent change when FERC approves the standards. We therefore suggest the SDT to also mark up those which have
newer versions already or soon to be adopted by the BoT and those that are being balloted. Alternatively, the SDT may
want to post the changes to those FERC approved standards only, and defer actions on those that have not been approved
by FERC and those that are being revised/balloted until FERC approves them.
(2) EOP-001: R7.3 has been changed to add the term “..., including outages to the Generator Interconnection Facility, to
maximize .....”. It is not clear whom the TOP and the BA should coordinate with and it does not place a requirement on the
entity that is responsible for the Generator Interconnection Facility outage planning and scheduling. We suggest to add the
appropriate responsible entity (Generator Owner?) to the Applicability Section, and add this entity to R7.3.
(3) In EOP-008 R1.3, is it the intent of the revised requirement that the plan address monitoring and control of ALL
Generator Interconnection Operational Interface[s] or just the critical ones (as with the critical transmission facilities)?
(4) R10 of TOP-001 is not written in the form of a requirement. We suggest replacing “have” with “exercise”. Thus, the
requirement would read “The Transmission Operator shall exercise decision-making authority over operation of the
Generator Interconnection Operational Interface...”
(5) TOP-004: The Applicability Section needs to be revised to add Generator Operator to reflect the new requirement R7.
We also suggest the SDT to evaluate if there is an alternative or more suitable place for this requirement than the TOP
standard.
(6) A number of standards are missing their VSLs. Most VSLs have similar wording in the requirements so many of them
will need to be revised to reflect changes to the requirements proposed in this project.
39
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT. The redlines were only
intended to provide stakeholders with an idea of the proposed scope of changes – the team recognizes that any new/revised requirement may result in
associated changes to the VRFs, Time Horizons, VSLs, data retention, measures, etc.
Energy Standards
Working Group
No
Comments: see my note re FAC-003
We are supportive of the modified requirements being suggested with the following exception:
FAC-003:We offer the following suggested changes for greater clarity.
4. Applicability:Replace the proposed sections 4.4 and 4.5 with the following:4.4. Generator Owner that owns a Generator
Interconnection Facility above 200 kV that exceed two spans from the generator property line or are below 200 kV and
deemed critical to the reliability of the electric system by the Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and subsequent sections of the
standards, it is clear that the use of the words “Generator Owner” refers only to the subset of Generator Owners as
specified by section 4.4, not to all Generator Owners included in the NERC Registry.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Constellation
Power Source
Generation Inc.
No
Constellation agrees with the proposed changes for BAL-5, EOP-1, EOP-4, EOP-8, FAC-1, FAC-8, FAC-9, IRO-5, MOD-10,
MOD-12, PER-1, PRC-1, PRC-5, TOP-1, TOP-2, TOP-3, VAR-1, and VAR-2. Furthermore, the changes made to CIP-2 are
especially valuable in that the clarity it brings with the added terminology would assist in identifying individual assets.
Constellation does not agree with (or has comments for) the proposed changes to:
oEOP-3 - GOs/GOPs should not be included in this standard
oFAC-3 - Constellation agrees in principal with this change, but further work is needed in regards to which GOs fall into this
category. The wording may be changed to “two or more spans exceeding ½ mile in total length,” but further discussions is
needed on this topic.
oPER-2 - Constellation agrees in principal with this change, but believes that this requirement should be combined into
PRC-001 R1, and eliminate the redundancy.
oPRC-5 - Testing of the Protection System of the Generator Interconnection Facility is not always the sole responsibility of
the GO. Some verbiage attesting to that is needed. Otherwise, it is wise to include the Generator Interconnection Facility
into this standard so that no gap may exist in the testing of a Protection System that may impact the BES.
40
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
E.ON U.S.
No
E.ON U.S. has already determined a Division of Responsibilities between the GO/TO and therefore does not see the need
for auditable reliability standards to be added between the GO/TO.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that there is a reliability need for
this SAR.
Duke Energy
No
o General Comment - The Standards Drafting Team (SDT) will need to make sure that Measures are developed or
modified to correspond to new or revised requirements of the standards.
o Process Question - Will the SDT fold these standards revisions into other projects, or will new versions be created as part
of this project?
o FAC-003-1 - Applicability sections 4.4 and 4.5 should be combined to make it clear that the standard only applies to the
Generator Owner’s GIF. Does the 2-span limit mean that there are three towers? What criteria will the Regional Entity use
to deem a GIF critical? The language about the generator property line is confusing - how does it compare to the Right-ofWay (ROW) definition? In some cases the TO may own the ROW, while the GO owns the GIF.
o FAC-008-1 - Requirement R1 raises a question regarding whether a GIF can be jointly owned by a TO and a GO. If a TO
is an owner, then the GIF is not a GIF but a transmission facility, right?
o FAC-009-1 - We don’t think revisions are needed to R1 and R2, since the term “Facilities” already implicitly includes GIF.
If you don’t agree, then perhaps a more straightforward approach would be to revise the definition of “Facility” to explicitly
include the GIF.
o IRO-005-2 - We think that you don’t need to specifically add the GIF to R9 because it would have to already be included
in the requirement as part of any generation outage coordination. Under R13 we would change “the Special Protection
System” to “any Special Protection System”. We also note that this new R13 propagates the poor language of R12 (i.e.,
how does anyone define “a potential failure to operate”?).
o PER-001-0 - Applicability section 4.3 should be expanded to make it clear that Requirement R2 only applies to the
Generator Operator with respect to the GIF, and R2 should be likewise revised. The GOP is already obligated under TOP001-1 Requirement R3 to comply with RC and TOP directives unless such actions would violate safety, equipment,
regulatory or statutory requirements. Suggested rewording of Applicability section 4.3 : “Generator Operators -This
standard shall apply to Generator Operators who own a Generator Interconnection Facility.” Suggested rewording of
Requirement R2 : “For Generation Facility Interconnection equipment under their direct control, each Generator Operator
shall provide operating personnel with the responsibility and authority to implement real-time actions and to follow reliability
41
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
directives of Reliability Authorities, Transmission Operators and Balancing Authorities, to ensure the stable and reliable
operation of the Generation Interconnection Facility.”
o PER-002-0 - Applicability section 4.3 should be expanded to make it clear that Requirement R2 only applies to the
Generator Operator with respect to the GIF. Suggested rewording of Applicability section 4.3 : “Generator Operators -This
standard shall apply to Generator Operators who own a Generator Interconnection Facility.”
o PRC-001-1 - Changes to PRC-001-1 should probably not be made right now, because it is already a vague standard, and
was the subject of an Interpretation (Project 2009-30) which was voted down in February.
o TOP-003-0 - Requirement R1 and its sub-requirements are poorly written. We suggest folding R1.3 into R1 with this
suggested rewording: “Generator Operators and Transmission Operators shall provide planned outage information by 1200
Central Standard Time for the Eastern Interconnection and 1200 Pacific Standard Time for the Western Interconnection, as
follows : “
o TOP-004-2 - We question whether Requirement R7 is appropriate, since by definition the GIF is not part of the
transmission system network and does not fit with the Purpose statement of this standard. If R7 is retained, then you need
to add Generator Operator to the Applicability section.
o TOP-008-1 - Need to add GOPs to the Purpose statement.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
California ISO
No
Please see our comments under Question 2 above. In addition, with regard to the proposed change to Standard PRC-001,
the California ISO (CAISO) questions the need for a BA to understand the purpose and limitations of protection schemes
associated with all of the Generator Interconnection Facilities in its area given a BA’s role is to balance
load/generation/interchange which does not require the BA to operate any generator or BES facilities, or to understand the
characteristics or limitations of any equipment. Any potential loss of one or more generator due to protection or equipment
issues will need to be communicated by the GO or GOP to the BA for consideration in reserve calculation
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Prairie Power, Inc.
No
PPI does not agree with the modification to EOP-003 R7. The Generator Operator does not have load to be shed,
therefore none to be coordinated. If the drafting team is intending to require the Generator Operator to coordinate the
underfrequency relay settings on their resources with load shedding plans established by the Transmission Operator and
Balancing Authority, this is an appropriate requirement. The modification, though, does not accomplish this.PPI questions
why the sustained line outages reported quarterly to the RRO pursuant to FAC-003 R3 by the Generator Owner, as
modified, are not reported to NERC in Requirement 4 of the same Standard.
42
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
AmerenUE, Power
Operations
Services
No
See response to Item #2.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard
or an existing standard(s).
Luminant
No
The following comments are specific to each standard
CIP-002 - This standard is currently under revision and any change should be addressed by the Cyber Security Standards
Revision Team.
EOP-003 - Application of this reliability standard to a GOP is incorrect. The Generator Operator has no direct responsibility
for load shedding. Only the TOP and BA have load shedding responsibility.
EOP-004 - The inclusion of GIF in this reliability standard is redundant as the GOP has responsibility for all of its facilities,
including any generators. . Since generation units are not independently identified with a particular GOP, the GIF does not
need to be independently identified. Also, there is a NERC project currently underway to revise this standard (Project 200901).
FAC-003 - Luminant agrees this standard should apply in those instances when the generator is connected to the BES
through its GIF over a substantial distance. However, the applicability of this standard to a GIF needs to specify a distance
(such as one-half (½) mile from the plant property boundary) not a number of spans since the spacing between spans can
vary from extensively. Defining the applicability of this standard in terms of a number of spans will create inconsistency in
the application of the requirements.
IRO-005 - New requirement R13 presumes that a Special Protection System (SPS) is the sole responsibility of a GOP,
which, in most cases, it is not. Most SPS are the responsibility of the TO, not the GOP. This requirement does not define
which SPS is being monitored. A requirement of this nature should define an SPS on the GIF.
PER-001 - The addition of a requirement applicable to GOP in this standard goes well beyond the scope of this project’s
purpose. A NERC Standards Drafting Team, under Project 2006-01, did not add any GOP requirements to the PER
standards. This proposed GOP requirement is redundant. Current NERC Reliability Standard TOP-001, R3 requires
Generator Operators to follow reliability directives, as does IRO-001, R8. This proposed requirement should be deleted. It
adds paperwork, documentation and compliance risk with no reliability benefit. The PER-001 standards were intended for
overall grid management, not the operation of a power plant.
43
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
PER-002 - The recent NERC Standards Drafting Team, under Project 2006-01, specifically declined to make this standard
applicable to GOP. In addition, the 2006-01 project is retiring this standard with the adoption of the revised PER-005.PRC001 - The inclusion of Generator Interconnection Facility is redundant. However, there is a current NERC Drafting team
revising PRC-001 and this issue should be referred to that team.
PRC-005 - Any revisions to PRC-005 should be referred to the current PRC-005 drafting team.
TOP-001 - Draft Requirements R9 and R10 are extremely broad. These should only apply to narrowly defined GIFs such
as long span connections or GIFs with transmission load flowing through the GIF. Care should be taken in this requirement
not to duplicate requirements such as coordination of outage planning. The requirements should be specific, and not fill in
the blank for the TOP or region.
TOP-004 - Draft Requirement R7 is redundant to requirements in other standards and is not needed.
IR0-005-2, R13, and IRO-005-3, R10, require the GOP to operate the BES to its most limiting factor, which is, by definition,
implicitly within its facility ratings.
TOP-008 - Does draft requirement R5 fit in this standard that addresses IROL and SOL? This requirement should only
apply to the same long connection GIF facilities identified in TOP-003.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Florida Municipal
Power Agency
No
The modification of EOP-003-1, R7 is inconsistent with the requirement. The original requirement requires the BA and TOP
to coordinate with others (presumably DPs, TOs and GOPs) in their area for various automatic action (e.g., UFLS,
automatic tripping of cap banks, and frequency capabilities of generators for instance). The GOP has no “area” to
coordinate and no one within its area to coordinate with. So, it is the BA and TOP that coordinate within their area, not the
entities embedded within the BA or TOP area. Otherwise, we ought to add at a minimum DPs, LSEs, and TOs to the list.
The modifications to EOP-004-1 R2; FAC-001-0 R1.1; FAC-008-1; FAC-009-1; MOD-010, MOD-012, PRC-001, PRC-004;
PRC-005; TOP-001-1 R7; TOP-002 R3 and R18; TOP-003 R1 and R1.1; and VAR-002 R3.2 are redundant with no need to
specifically call out the Generator Interconnection Facility. The interconnection facilities are facilities and already included in
the term “on its system or facilities” and “generating facilities”, etc. And, the Generator Owner and Operator are already
responsible for their interconnection facilities in the definition of those Entities. Specifically calling out the interconnection
facilities calls into question why other facilities are not specifically called out.
As discussed in the response to #2 above, addition of the Generator Owner to FAC-003 over-steps Federal Power Act
Section 215 since radial transmission lines to generating plants will not participate in a cascading outage since the loading
of radial facilities to power plants will not change significantly with outages on the interconnected system.
44
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
North Carolina
Electric
Membership
Corporation
No
We agree with most all of the modified requirements with one exception:
For FAC-003, regarding the "two-span criteria" or "about 0.5 miles" test for generator applicability, we would like the ad hoc
team to consider providing more direction or greater specificity that makes a GIF of two or less spans to become exempt,
while one of greater than two spans (0.5 mile) but less then 5 spans (0.8 miles) to suddenly become subject to the FAC-003
standard requirements. The "generator's line-of sight" rule as described in response to item #3 in the Final Report in our
opinion should be clearly specified in the FAC-003 proposed standard change at a minimum to avoid mis-interpretations.
Also, regarding item #10 issue in the report, we would like the ad hoc team to consider proposing a 4th proposal which
would be a hybrid between Proposal 2 and Proposal 3 as reported within the Final Report which would provide a “bright-line
test” as to what generators are exempt or not to the FAC-003 standard, rather than solely relying on Proposal 2 which relys
on the physical attributes of the GIF in ruling out generators subject to FAC-003. If the GIF is 3-4 spans or 0.53 miles in
length, but still within the "line of sight" of the GOP, then allow the GOP working with the RE and TOP to rule out smaller
generators that are immaterial to the reliability of the grid.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Tenaska, Inc.
No
We are supportive of the modified requirements being suggested with the following exception related to the suggested
changes on FAC-003 for which we offer the following modification for greater clarity:
4. Applicability:Replace the proposed sections 4.4 and 4.5 with the following:
4.4. Generator Owner that owns a Generator Interconnection Facility above 200 kV that exceed two spans from the
generator property line or are below 200 kV and deemed critical to the reliability of the electric system by the
Regional Entity (subject to the two-span criteria.)
Furthermore, the Standard Drafting Team should insure that in drafting the requirements and subsequent sections of the
standards, it is clear that the use of the words “Generator Owner” refers only to the subset of Generator Owners as
specified by section 4.4, not to all Generator Owners included in the NERC Registry.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Midwest ISO
Standards
Collaborators
No
We do not agree with the modification to EOP-003 R7. The Generator Operator does not have load shed to coordinate.
We believe the drafting team is intending to require the Generator Operator to coordinate underfrequency relay settings on
their generators with the BA and TOP load shedding plans. We agree this is appropriate but the modification does not
45
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
accomplish this.
EOP-004 R2 seems to be modified unnecessarily. System and facilities are already included in the requirement and, thus,
would include the Generator Interconnection Facility.
We do not agree adding Generator Interconnection Operational Interface to R1.3 in EOP-008. The sub-requirement
already requires the contingency plan to consider generation control which would require consideration of the Generator
Interconnection Operational Interface. Furthermore, there is a lack of coordination with the project to update this standard.
A newer, significantly modified version of this standard has already been through an initial ballot period.
IRO-005 R9 modifications are not needed. The requirement already requires an RC to coordinate pending generation
outages. This would have to include any outage such as the Generator Interconnection Facility.Many of the changes to the
TOP standard are modifying requirements that the Real-Time Operations standards drafting team has already proposed for
removal. This project needs to be coordinated with the Real-Time Operations project.
VAR-001 R8 modifications are not necessary because the TOP is already required to operate reactive generation
scheduling. They can’t do this without considering the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
ISO RTO Council
Standards Review
Committee
No
While we generally agree with the proposed wording change, we have a number of comments the first of which is a timing
decision issue.
(1) We realize that the SDT needs to make changes to “approved standards” but there are a number of standards involved
in this project whose newer versions have either received the BoT approval, or about to be adopted by the BoT or at the
stage of being finalized or balloted. To make changes to the soon to be outdated versions is confusing and will require a
subsequent change when FERC approves the standards. We therefore suggest the SDT to coordinate their changes with
the other drafting teams that are working on the newer versions already or soon to be adopted by the BoT and those that
are being balloted. Alternatively, the SDT may want to post the changes to those FERC approved standards only, and defer
actions on those that have not been approved by FERC and those that are being revised/balloted until FERC approves
them.
(2) EOP-001: R7.3 has been changed to add the term “..., including outages to the Generator Interconnection Facility, to
maximize .....”. It is not clear with whom the TOP and the BA should coordinate with and it does not place a requirement on
the entity that is responsible for the Generator Interconnection Facility outage planning and scheduling. We suggest
removing the changes on this requirement all together. Generator maintenance will include the Generator Interconnection
Facility. These are extra words that are not needed.
(3) A number of standards are missing their VSLs. Most VSLs have similar wording in the requirements so many of them
46
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
will need to be revised to reflect changes to the requirements proposed in this project.
(4) We do not agree with the modification to EOP-003 R7. The Generator Operator does not have load shed to coordinate.
We believe the drafting team is intending to require the Generator Operator to coordinate underfrequency relay settings on
their generators with the BA and TOP load shedding plans. We agree this is appropriate but the modification does not
accomplish this.
(5) EOP-004 R2 seems to be modified unnecessarily. System and facilities are already included in the requirement and,
thus, would include the Generator Interconnection Facility.
(6) We do not agree adding Generator Interconnection Operational Interface to R1.3 in EOP-008. The sub-requirement
already requires the contingency plan to consider generation control which would require consideration of the Generator
Interconnection Operational Interface. Furthermore, there is a lack of coordination with the project to update this standard.
A newer, significantly modified version of this standard has already been through an initial ballot period.
(7) IRO-005 R9 modifications are not needed. The requirement already requires an RC to coordinate pending generation
outages. This would have to include any outage such as the Generator Interconnection Facility.
(8) PRC-001: We question the need for a BA to understand the purpose and limitations of protection schemes associated
with all of the Generator Interconnection Facilities in its area given a BA’s role is to balance load/generation/interchange
which does not require the BA to operate any generator or BES facilities, or to understand the characteristics or limitations
of any equipment. Any potential loss of one or more generator due to protection or equipment issues will need to be
communicated by the GO or GOP to the BA for consideration in reserve calculation.
(9) Many of the changes to the TOP standard are modifying or adding parallel requirements that the Real-Time Operations
standards drafting team has already proposed for removal. This project needs to be coordinated with the Real-Time
Operations project to assess the need for these additions/modifications.
(10) VAR-001 R8 modifications are not necessary because the TOP is already required to operate reactive generation
scheduling. They can’t do this without considering the Generator Interconnection Facility.
Response: The SAR DT thanks you for your comment. Several stakeholders had similar concerns, and all will be referred to the SDT.
Bonneville Power
Administration
Yes
Competitive Power
Ventures, Inc.
Yes
47
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Detroit Edison
Company
Yes
El Dorado Energy
LLC
Yes
Electric Market
Policy
Yes
Entegra Power
Group LLC, i.e.,
Gila River Power
and Union Power
Partners
Yes
First Wind
Yes
Ingleside
Cogeneration, LP
Yes
Kansas City Power
& Light
Yes
Mesquite Power
Yes
PSEG Companies
Yes
Sempra
Generation
Yes
SERC Planning
Standards
Subcommittee
Yes
Question 5 Comment
48
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
South Carolina
Electric and Gas
Yes
Southern California
Edison co.
Yes
Question 5 Comment
Additional clarification would be useful as it/ they would cut down on future requests for interpretation
Response: The SAR DT thanks you for your comment.
American Electric
Power
Yes
AEP feels that a majority of the standards that were modified add clarity. We reserve the right to comment when the
Standard Drafting Team posts the draft Standard(s).
Response: The SAR DT thanks you for your comment. There will be additional opportunities to comment on the specific proposed modifications when the
project progresses to standard drafting.
Public Utility
District #1 of Clark
County
Yes
Except as discussed in comments 2, 3, and 4, Clark is in agreement with the proposed changes.
Response: The SAR DT thanks you for your comment.
American
Transmission
Company
Yes
For FAC-009 [Establish and Communicate Facility Ratings], we believe that the additional wording to highlight that the term
“Facilities” includes “Generation Interconnection Facilities” is superfluous, and therefore, it should not be added. The
proposed new and revised definitions provide more than enough clarity
For MOD-010 [Steady State Data for System Modeling], we believe that the additional wording of “for plant and Generator
Interconnection Facilities” is superfluous, and therefore, it should not be added. The proposed new and revised definitions
provide more than enough clarity.
For MOD-012 [Dynamic System Data for System Modeling], we believe that the additional wording of “for plant and
Generator Interconnection Facilities” is superfluous, and therefore, it should not be added. The proposed new and revised
definitions provide more than enough clarity.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Entegra Power
Yes
SEE COMMENTS FOR QUESTION 2.
49
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or
No
Question 5 Comment
Group LLC
Response: The SAR DT thanks you for your comment. Please see the response to your comments on Question 2.
Manitoba Hydro
Yes
The modifications at this point appear appropriate.
Response: The SAR DT thanks you for your comment.
Pepco Holdings,
Inc - Affiliates
Yes
There should be a clause that the TO shall be responsible for FAC-003 activities inside the TO's substation regardless of
ownership of the Generation Interconnection Facility so we don't have to coordinate entry, etc. and they will likely have this
handled for the bulk of their property anyway.R3 quarterly reporting of outage caused by vegetation is excessive for GOs.
GOs would probably survey and cut as needed their Right of Ways at least once a year and probably already do so. TOs
probably perform vegetation management on a multi-year cycle, so they might need to note quarterly if there is a veg.
incident that occurs one or two quarters before the next round of survey/management on that line.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. There were many suggestions for additional or alternate modifications to
FAC-003 and these suggestions will be addressed by the SDT.
50
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
6. Do you believe there are any other Transmission Owner or Transmission Operator standards or requirements
that should be applicable to the Generator Owner or Generator Operator other than those identified?
Summary Consideration: Stakeholders did not indicate the need to include any requirements or standards that were not already contained
in the SAR. However, based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC compliance filings,
the SAR DT modified the SAR to give the SDT the flexibility to consider further modifications not identified in the Ad Hoc Report.
Organization
Yes or No
AmerenUE, Power Operations
Services
No
American Transmission
Company
No
Bonneville Power Administration
No
California ISO
No
Competitive Power Ventures, Inc.
No
Constellation Power Source
Generation Inc.
No
Detroit Edison Company
No
E.ON U.S.
No
El Dorado Energy LLC
No
Electric Market Policy
No
Energy Standards Working
Group
No
Question 6 Comment
51
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Entegra Power Group LLC
No
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
No
First Wind
No
Florida Municipal Power Agency
No
Independent Electricity System
Operator
No
Ingleside Cogeneration, LP
No
ISO RTO Council Standards
Review Committee
No
Luminant
No
Mesquite Power
No
Midwest ISO Standards
Collaborators
No
North Carolina Electric
Membership Corporation
No
Pepco Holdings, Inc - Affiliates
No
Prairie Power, Inc.
No
PSEG Companies
No
Question 6 Comment
52
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Yes or No
Public Utility District #1 of Clark
County
No
Sempra Generation
No
SERC Planning Standards
Subcommittee
No
South Carolina Electric and Gas
No
Tenaska, Inc.
No
American Electric Power
No
Question 6 Comment
At this point in time, AEP cannot identify any other TO/TOP requirements that should be considered.
Response: The SAR DT thanks you for your comment.
Southern California Edison co.
No
Do not feel that this question is in the scope of Project 2010-07 as written
Response: The SAR DT thanks you for your comment.
Duke Energy
No
However the SDT should perform a complete review.
Response: The SAR DT thanks you for your comment. The SDT will review all applicable standards changes as needed and required by the scope and
purpose of the SAR.
Manitoba Hydro
No
No manpower available at this time to examine all possibilities and scenarios.
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
No
Not at this time.
Response: The SAR DT thanks you for your comment.
53
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
7. The next posting of the proposed revisions to these standards will include conforming changes to the measures
and compliance elements, and will include an implementation plan. Please identify how much time you feel an
entity will need to become fully compliant with the following new/revised requirements:
The Generator Operator who has responsibility for monitoring the status of a special protection system or remedial action scheme at the
generating facility for the benefit of Bulk Electric System reliability should notify the Transmission Operator when a change in status or
capability occurs. (IRO-005)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question and its subcomponents. This series of
questions was meant to provide input for the SDT in development of the required implementation plan that will accompany this project as it
moves forward. The SAR DT would like to note that the three challenges most cited were training, agreements, and technical details. This
information will be referred to the SDT for their consideration.
Organization
Pepco Holdings, Inc - Affiliates
Time
Question 7 Comment
No SPS currently in system.
Response: The SAR DT thanks you for your comment.
California ISO
We are not a GOP and hence we are unable to comment on this and other questions addressing the GOP
compliance. However, the CAISO has the following comments on the effort required for other aspects of
this Project:
o As discussed under the answer to Question 5 above, it is not clear if the proposed changes to PRC-001
will require the Balancing Authority (BA) to understand the purpose and limitations of protection schemes
associated with all of the Generator Interconnection Facilities in its area, even if such facilities are not
under the control of the BA. If this is the case, significant and time-consuming effort will be required to
identify the technical details of all of the Generator Interconnection Facilities in the BA and develop a
training program to train applicable personnel on them. This is estimated to require up to 24 months.
o If the proposed changes are approved they will affect 16 Standards affecting CAISO registrations. Most,
if not all, of these changes will require modifications to the Reliability Standards Agreements (RSAs)
between the CAISO and its Participating Transmission Operators to reflect the new wording and any
delegated tasks. This may require 12 to 24 months to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
54
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
Kansas City Power & Light
12 months
Question 7 Comment
Basically this is a training issue. It takes time to prepare the training materials and to train all Generator
Operators considering shift schedules and to implement the training as part of an ongoing process.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
18 months
Luminant
18 months
55
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
South Carolina Electric and Gas
18 months
Electric Market Policy
18 months to
two years
Question 7 Comment
We feel that, in most cases, such monitoring will only require RTU connectivity of the data points as well as
incorporation into GOP control room displays.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but would probably be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Immediately
unless status
requires
change to
additional
requirements
which might
be 18 months
to two years)
The Generator Interconnection Facilities are already considered to be part of our Generator Plant and
therefore have already been included in our existing compliance program.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time
Clark has no SPS or RAS for which it is responsible.
Response: The SAR DT thanks you for your comment.
56
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Florida Municipal Power Agency
Time
Question 7 Comment
The amount of
time it takes to
compile
documentation
to fulfill the
data retention
requirements
of the
requirement
For most of these new requirements, the Entities are most likely fulfilling the requirements, but, may be
missing the documentation to prove that they are doing so. So, to be auditably (“fully”) compliant, the
Entities will need the amount of time it takes to build up sufficient evidence of compliance. This may only be
a month to develop documentation, to a longer period of time to prove periodicity (e.g., a PRC-005 type of
requirement - not PRC-005 itself - but a requirement that may need to be done periodically such as training
to show that it is done periodically.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
57
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
a. Each Generator Operator shall provide its operating personnel with the responsibility and authority to
implement real-time actions to ensure the stable and reliable operation of the Generation Facility and the
Generation Interconnection Facility, and to implement directives of the Transmission Operator and Balancing
Authority. (PER-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question and its subcomponents. This series of
questions was meant to provide input for the SDT in development of the required implementation plan that will accompany this project as it
moves forward. The SAR DT would like to note that the three challenges most cited were training, agreements, and technical details. This
information will be referred to the SDT for their consideration.
Organization
Time
American Electric Power
Question 7a Comment
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
Response: The SAR DT thanks you for your comment. These comments will be referred to the SDT.
Pepco Holdings, Inc - Affiliates
These responsibilities and authorities are already in place for other standards.
Response: The SAR DT thanks you for your comment. These comments will be referred to the SDT.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
58
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7a Comment
Regulatory
Approval
Luminant
18 months
Energy Standards Working
Group
2 years
Tenaska, Inc.
2 years
Constellation Power Source
Generation Inc.
2 years
Time is needed for training and terminology to percolate throughout the Generation Facility and that it be
ingrained with the Operators.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
6 months
Duke Energy
Approximately
24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Less than 1
year
Memo from management should suffice.
Electric Market Policy
Less than one
year
Memo from management should suffice.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Kansas City Power & Light
N/A
The Generator Operator should be operating equipment within the Generator Interconnection Facility at the
59
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7a Comment
direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No Time.
Clark’s Generator Operator personnel have responsibility and authority to implement real-time actions to
ensure the stable and reliable operation of the Generation Facility and the Generation Interconnection
Facility, and to implement directives of the Transmission Operator and Balancing Authority.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
60
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
b. Each Generator Operator shall implement an initial and continuing training program for all personnel
responsible for operating the Generator Interconnection Facility to ensure the ability to operate the equipment
in a reliable manner. (Per-002)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7b Comment
A training program for this would need to be created, procedures approved, implemented, and instituted at
all power plants for all shifts. E.ON U.S. recommends that the addition of PER-002 R3 be coordinated with
the existing standard PRC-001 R1, to eliminate redundancy.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
American Electric Power
AEP believes that this requirement is not needed and should be out of the scope for this SAR.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Pepco Holdings, Inc - Affiliates
0-2 years
Currently establish training based on the RTO requirements. It would be Conectiv’s policy to continue this
training for this requirement. If other training is imposed upon the Entities, it may require up to two years to
develop and initiate full training.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Entegra Power Group LLC
1 YEAR
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
12 months
61
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7b Comment
Membership Corporation
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Energy Standards Working
Group
2 years
Tenaska, Inc.
2 years
First Wind
2 years
Developing the training and providing it while accommodating shift employees will require a substantial
amount of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
2 years
Time is needed to implement a training plan and revise it based on feedback from those being trained.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
2-3 years,
depending on
the extent of
equipment
involved and
size of facility.
Luminant
24 months
Prairie Power, Inc.
24 months
following
Regulatory
Approval
62
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Southern California Edison co.
Time
3yrs
Question 7b Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Duke Energy
Approximately
24 months.
Multiple shifts and multiple facilities will require time to get training developed and delivered.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Kansas City Power & Light
N/A
The Generator Operator should be operating equipment within the Generator Interconnection Facility at the
direction of the Transmission Operator.
Response: The SAR DT thanks you for your comment. We will refer these comments to the SDT.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
Public Utility District #1 of Clark
County
Twelve
months.
Clark’s generating operating personnel regularly engage in training however, to implement a Training
Program as rigorous as the TOP Training Program will take some time to complete.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Electric Market Policy
two years
Developing the training and providing it while accommodating shift employees will require a substantial
amount of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
63
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
c. The Generator Operator shall coordinate the operation of its Generator Interconnection Facility with the
Transmission Operator to whom it interconnects to preserve Interconnection reliability. (TOP-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7c Comment
Appears redundant with point e) below. There are already generator-outage reporting protocols in place.
This would be an unnecessary addition to existing processes.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
64
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
Luminant
18 months
South Carolina Electric and Gas
18 months
Prairie Power, Inc.
24 months
following
Regulatory
Approval
Southern California Edison co.
3yrs
Question 7c Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
Less than 1
year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes. Additionally, the Generator Interconnection Facility is already considered to be part of the
Generating Facility and is likely already part of our existing compliance program.
65
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7c Comment
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
There is already generator outage reporting protocols in place. This is just an addition to existing
processes.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No Time.
Clark believes the operation of its generator is already under the direction of its TOP and that coordination
has already occurred since the TOP has included the operation of Clark’s generator in its TOP-002 Normal
Operations Plan.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
66
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
d. The Transmission Operator has decision-making authority for the Generator Interconnection Operational
Interface. (TOP-001)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Pepco Holdings, Inc - Affiliates
Time
0-2 years
Question 7d Comment
Coordination is required for the TOP to notify the GO/GOP of the decisions being implemented.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
67
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
SERC Planning Standards
Subcommittee
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
18 months
South Carolina Electric and Gas
18 months
Southern California Edison co.
3yrs
Question 7d Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment. Please see the response to question 8.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this because the Generator Interconnection Facility
is already considered to be part of the Generating Facility.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
68
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
Question 7d Comment
Clark believes that existing standards already grant the TOP decision-making authority for the Generator
Interconnection Operational Interface.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
69
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
e. The Generator Operator shall notify the Transmission Operator of a change in status of the Generation
Interconnection Facility.
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Pepco Holdings, Inc - Affiliates
Time
0-2 years
Question 7e Comment
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
70
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Luminant
18 months
Southern California Edison co.
3yrs
Question 7e Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Bonneville Power Administration
6 months.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
8 months
Duke Energy
Approximately
3 months
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
Less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
71
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Public Utility District #1 of Clark
County
Time
No time.
Question 7e Comment
Clark’s Generation Interconnection Facility status is already provided to the TOP in real time over the
TOP’s SCADA system.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
72
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
f. The Generator Operator shall operate the Generation Interconnection Facility within Facility Ratings. (TOP004)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
American Electric Power
Question 7f Comment
AEP does not believe that the added requirement is necessary as the Generator Interconnection Facility
should be adequately sized to handle the output of the generator.
Response: The SAR DT thanks you for your comment. Based on a review of the full body of industry comments, we believe that the standards actions proposed in
this SAR are appropriate. Specific modifications will be determined by the SDT.
Bonneville Power Administration
0 months.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently operates within the facility ratings as required under FAC. If additional requirements are
instituted by NERC, there may be a need to have time to develop new programs and policies to comply with
additional requirements
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
12 months
73
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7f Comment
Subcommittee
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
18 months
South Carolina Electric and Gas
18 months
Southern California Edison co.
3yrs
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
6 months
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
The Generator Interconnection Facility is already considered to be part of the Generator Unit and the facility
should be compliant currently with FAC standards.
Response: The SAR DT thanks you for your comment.
Electric Market Policy
less than one
year
Facility should be compliant currently with FAC standards.
74
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7f Comment
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
The Generation Interconnection Facilities of Clark have ratings that exceed the maximum generating
capability of the interconnected generation facility.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
75
Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
g. The Generator Operator shall disconnect the Generation Interconnection Facility immediately in coordination
with the Transmission Operator when time permits or as soon as practical thereafter if an overload or other
abnormal condition threatens equipment or personnel safety. (TOP-008)
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. This series of questions was meant to
provide input for the SDT in development of the required implementation plan that will accompany this project as it moves forward. The SAR
DT would like to note that the three challenges most cited were training, agreements, and technical details. This information will be referred to
the SDT for their consideration. The time needed to comply varied from 0-3 years.
Organization
Time
E.ON U.S.
Question 7g Comment
In case of overload, the E.ON U.S. GOP has an overload current relay that already removes a generating
unit from the grid immediately. Moreover, it is expected that in most cases an Interconnection Agreement
between the generator and TO that it connects with already contains language supportive of this.
Response: The SAR DT thanks you for your comment.
Pepco Holdings, Inc - Affiliates
0-2 years
Entity currently coordinates this operation with the TOP. If additional requirements are instituted by NERC,
there may be a need to have time to develop new programs and policies to comply with additional
requirements.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Constellation Power Source
Generation Inc.
1 year
Energy Standards Working
Group
1 year
Tenaska, Inc.
1 year
Bonneville Power Administration
1 year, if
agreements
need to be
renegotiated.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
12 months
North Carolina Electric
Membership Corporation
12 months
SERC Planning Standards
Subcommittee
12 months
South Carolina Electric and Gas
12 months
Prairie Power, Inc.
12 months
following
Regulatory
Approval
Luminant
36 months
Southern California Edison co.
3yrs
Question 7g Comment
Pls refer to question No. 8
Response: The SAR DT thanks you for your comment.
Kansas City Power & Light
6 months
If this is not already going on, this should not take long to implement.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
Duke Energy
Approximately
3 months.
Depends upon measures and data requirements, but should be a short period of time.
Response: The SAR DT thanks you for your comment. All timing issues related to the implementation plan will be addressed by the SDT.
First Wind
less than 1
year
The Generator Interconnection Facility is already considered to be part of the Generator Unit. Expect that,
in most cases, the Interconnection Agreement between the generator and the TO or DP that it connects
with already contains language that supports this.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Time
Question 7g Comment
Response: The SAR DT thanks you for your comment.
Electric Market Policy
less than one
year
Expect that, in most cases, the Interconnection Agreement between the generator and the TO or DP that it
connects with already contains language that supports this.
Response: The SAR DT thanks you for your comment.
Entegra Power Group LLC
NO
COMMENT
Public Utility District #1 of Clark
County
No time.
Clark has experienced no operating conditions where it had to disconnect the Generation Interconnection
Facility immediately due to an overload or other abnormal condition that threatened equipment or personnel
safety.
Response: The SAR DT thanks you for your comment.
Florida Municipal Power Agency
See above
See above
Response: The SAR DT thanks you for your comment.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
8. If you have any other comments on this SAR or proposed standard revisions and NERC Glossary modifications
that you have not already provided in response to the prior questions, please provide them here.
Summary Consideration: The SAR DT thanks all stakeholders for their response to this question. Many of the comments were
addressed in earlier responses. Based on discussions with FERC and NERC staffs regarding previous Commission actions and NERC
compliance filings, the SAR DT modified the SAR to give the SDT the flexibility to consider further modifications not identified in the Ad Hoc
Report. Finally, revisions to the SAR also allow the SDT the option of merging the changes into one new standard or into several different
existing standards.
Organization
Constellation Power Source
Generation Inc.
Question 8 Comment
Constellation would like to thank the Ad-Hoc group for the excellent work they did in creating the GOTO Final Report. In
particular, here are a few excerpts that Constellation agrees with, and would like the future SDT to consider:
oThe Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility.
oA Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator.
oAfter review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators, no
existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility.
Response: The SAR DT thanks you for your comments. The SAR DT supports the three concepts identified.
El Dorado Energy LLC
El Dorado Energy commends the efforts of the NERC Ad Hoc Group, and supports the Final Report from the Ad Hoc Group
for Generator Requirements at the Transmission Interface, and Standards Authorization Request addressing the various
Standards containing GO/GOP and TO/TOP Requirements. The Final Report and SARs are products of detailed analysis
and thoughtful consideration of the myriad issues surrounding the reliability implications of ownership and operation of
Generator Interconnection Facilities. It is noteworthy - though hardly surprising - that, after many months of study, the GO/TO
Task Force, a balanced group comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator interconnection facilities are
operated reliably. When implemented, the recommendations included in the Final Report and SARs should go a long way
toward providing the regulatory and compliance certainty needed by generators who own or operate Generator
Interconnection Facilities. Accordingly, El Dorado Energy encourages the Standards Drafting Team to act quickly to
implement the SARs.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
Response: The SAR DT thanks you for your comment.
Competitive Power Ventures,
Inc.
Every effort should be made to precisely describe requirements that directly correspond to, and address, the reliability issues
framed by the GO/TO Ad Hoc Group. Particularly, "interconnection facilities" should be defined to account for and exclude
various transmission configurations on the generator side of the interconnection point that do not create network power flows
or otherwise operate as bona fide transmission systems.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
Entegra Power Group LLC, i.e.,
Gila River Power and Union
Power Partners
FAC-003 - Applicability apply to GIF above 200 kV that exceed two spans should be revised to "less than one-half mile" as
span lengths vary considerably. For example we have 3 spans over 1/4 mile.R1. requirement to "keep current, a formal
TVMP" should allow latitude for those entities with one-quarter mile of radial connecting transmission, all visible from the
office window, to have a less than a formal program, or at least a very SIMPLE program.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
First Wind
FAC-003 - Step 4.5 should be clearly identified as a “qualifier” for Generator Owner applicability. Although not the intent of
the standard, as currently drafted, the requirements apply to all Generator Owners. Additionally we recommend
modifications to address a disqualifier if the plant is located in an environment whose natural environment would prevent
vegetation from growing that could interfere with the reliability of the bulk Electric System. The following changes are
recommended.
4.4. Generator Owner.
4.5. This standard shall apply to the Generator Interconnection Facility above 200 kV that exceed two spans from the
generator property lineor are otherwise deemed critical by the Regional Entity below 200 kV (subject to the two-span
criteria.). This standard does not apply to all Generator Interconnection Facilities outside this threshold and those
facilities located in an area whose environment would prevent vegetation from growing.A generating facility located
underground, in the high desert or within a fully developed urban area where vegetation disturbances could not occur
should not be required to have a vegetation management program.
o MOD-010 - The changes made in this standard are not reflected in the associated standard, MOD-011 (possibly because
MOD-011 is not FERC approved).
o MOD-012 - The changes made in this standard are not reflected in the associated standard, MOD-013 (possibly because
MOD-013 is not FERC approved).
o PER-001 - The Purpose statement in the Standard needs to be modified to include GOP.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
o PER-002 - The Purpose statement in the Standard needs to be modified to include GOP.We recommend the addition of
PER-002 R3 is coordinated with the existing standard PRC-001 R1 to eliminate redundancy. While PER-002 R3 more clearly
calls for training, PRC-001 R1 implies training. The two standards should be combined into one training requirement.PRC001 R1 “Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar with the purpose and
limitations of protection system schemes applied in its area.”We recommend retiring PRC-001 R1 and modifying the
proposed standard PER-002 R3 as shown below:
Each Generator Operator shall implement an initial and continuing training program for all operating personnel that are
responsible for operating the Generator Protection System Equipment, including the Generator Interconnection Facility
that verifies the personnel’s ability and understanding to operate the equipment in a reliable manner.
o o TOP-002 - Requirement R14 contains sub-requirements R14.1 and R14.2 that were retired August, 1, 2007. Suggest
deleting the retired requirements with the proposed revision.
o TOP-004 - Requirement R7 has been added for the Generator Operator; however, the Generator Operation has not been
added to the Applicability.
o TOP-008 - The Purpose statement in the Standard needs to be modified to include GOP.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT.
California ISO
It does not appear that any of the Measures in the proposed Standards have been revised to reflect the new and/or revised
requirements.
Response: The SAR DT thanks you for your comment. The intent was to post just the initial set of proposed requirements to provide stakeholders with a sense of
the scope of the project. The SDT assigned to this project will need to work with stakeholders to develop not only the requirements, but all the other elements
needed to support those requirements, including measures, violation risk factors, time horizons, violation severity levels, evidence retention, etc.
North Carolina Electric
Membership Corporation
NCEMC is concerned with the decision to use “revisions to the latest versions of the following standards” that were included
in red-line format in this SAR: o BAL-005 o CIP-002 o EOP-001, -003, -004, -008 o FAC-001, -003, -008, -009 o IRO-005
o MOD-010, -012 o PER-001, -002 o PRC-001, -004, -005 o TOP-001, -002, -003, -004, -008 o VAR-001, -002
The use of these versions of the standards, many of which have been revised, approved by the NERC Board of Trustees and
filed with FERC emphasizes the flaw in a regulatory approval process that is not uniform throughout North America. Not all
registered entities are FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon NERC
Board of Trusteesapproval. Of the standards that are included in this SAR, three projects not including nterpretations have
been retired, modified, or new standards created that are now complied with by some registered entities. The projects
include; Project 2006-01 ― System Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 ― Cyber Security ― Order
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
706 ― CIP-002 through CIP-009. In addition, it is difficult to determine whether there is any coordination between the
activities of this SAR drafting team and those ofthe many existing drafting teams that are also revising standards. NCEMC
understands the dilemma of how to revise standards in a regulatory environment that has no defined time-line guidelines for
approval of standards upon filing with FERC, but reminds NERC, the Standards Committee and drafting teams that the
process must address the varying regulatory approval processes in NorthAmerica.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT. The SDT will work with the latest BOT approved versions of the
standards in support of your comment.
SERC Planning Standards
Subcommittee
No other comments
Kansas City Power & Light
No other comments.
South Carolina Electric and Gas
none
National Rural Electric
Cooperative Association
(NRECA)
NRECA is concerned with the decision to use “revisions to the latest versions of the following standards” that were included in
red-line format in this SAR: o BAL-005 o CIP-002 o EOP-001, -003, -004, -008 o FAC-001, -003, -008, -009 o IRO-005
o MOD-010, -012 o PER-001, -002 o PRC-001, -004, -005 o TOP-001, -002, -003, -004, -008 o VAR-001, -002The use
of these versions of the standards, many of which have been revised, approved by the NERC Board of Trustees and filed with
FERC emphasizes the flaw in a regulatory approval process that is not uniform throughout North America. Not all registered
entities are FERC jurisdictional, therefore, are already required to comply with Reliability Standards upon NERC Board of
Trustees approval. Of the standards that are included in this SAR, three projects not including interpretations have been
retired, modified, or new standards created that are now complied with by some registered entities. The projects include;
Project 2006-01 ― System Personnel Training ― PER-002, PER-004, and PER-005, Pre-2006 ― Operate Within
Interconnection Reliability Operating Limits − IRO-007 through IRO-010 and Project 2008-06 ― Cyber Security ― Order
706 ― CIP-002 through CIP-009. In addition, it is difficult to determine whether there is any coordination between the
activities of this SAR drafting team and those of the many existing drafting teams that are also revising standards. NRECA
understands the dilemma of how to revise standards in a regulatory environment that has no defined time-line guidelines for
approval of standards upon filing with FERC, but reminds NERC, the Standards Committee and drafting teams that the
process must address the varying regulatory approval processes in North America.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT. The SDT will work with the latest BOT approved versions of the
standards in support of your comment.
Electric Market Policy
oEOP-003 - I do not understand the addition of GOP to this standard. Additionally, the Purpose statement is not in
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
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Question 8 Comment
alignment with the additional GOP applicability.
oFAC-003 - Step 4.5 should be clearly identified as a “qualifier” for Generator Owner applicability. Although not the intent of
the standard, as currently drafted, the requirements apply to all Generator Owners.
oMOD-010 - The changes made in this standard are not reflected in the associated standard, MOD-011 (possibly because
MOD-011 is not FERC approved).
oMOD-012 - The changes made in this standard are not reflected in the associated standard, MOD-013 (possibly because
MOD-013 is not FERC approved).
oPER-001 - The Purpose statement is not in alignment with the additional GOP applicability.
Response: The SAR DT thanks you for your comments. They will be referred to the SDT.
American Electric Power
Overall, AEP supports the concept of this SAR, but we question the number of new requirements that are being brought in
scope. Some of the requirements added appear to encourage this SAR to reach farther than the scope of addressing the
Generator Interconnection Facilities.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. The intent of the SAR was to collect feedback on the proposed scope of this
project.
Prairie Power, Inc.
PPI contends this SAR and associated requirement additions and revisions go well beyond the recommendations from the
Group needed to resolve the barrier issue between Transmission Operator and Generator Operator. The FAC-003 standard
revision, so that vegetation management can be enforced for transmission lines which interconnect generators to
transmission, is really all that is necessary. All these other changes just add confusion to already overlapped requirements.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. One of the goals of this project is to eliminate ‘overlaps’ so there is a clear
line of responsibility for each facility.
Southern California Edison co.
SCE believes that implementing changes type of changes proposed in 2010-07 should be looked at as a whole/ one entire
project rather than piece meal as alluded to in question number 7 of the comments form. As such, it is the company’s
position that approximately 3yrs is right amount of time to reliably implement the proposed revisions to the suite of standards
as identified in Project 2010-07. A 3 yr timeline would enable the project to be fully scoped out and budgeted, and allow for:
completion of the necessary engineering studies; design, procurement and construction of any new facilities necessitated by
the revisions; development of any new operations and communications procedures with respect to both the transmission and
generation facilities; and the training of personnel related to any new procedures.
Response: The SAR DT thanks you for your comment. The SAR has been modified to allow the SDT the option of merging the changes into one new standard or an
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
existing standard(s). All timing issues related to the implementation plan will be addressed by the SDT. As envisioned, all requirements would become effective at the
same time as the proposed definitions to ensure that there are no gaps in the body of NERC requirements.
Sempra Generation
Sempra Generation commends the efforts of the NERC Ad Hoc Group, and supports the Final Report from the Ad Hoc Group
for Generator Requirements at the Transmission Interface, and Standards Authorization Request addressing the various
Standards containing GO/GOP and TO/TOP Requirements. The Final Report and SARs are products of detailed analysis
and thoughtful consideration of the myriad issues surrounding the reliability implications of ownership and operation of
Generator Interconnection Facilities. It is noteworthy - though hardly surprising - that, after many months of study, the GO/TO
Task Force, a balanced group comprised of members from a broad spectrum of functional categories, concluded that only
modest changes to the Reliability Standards would be required in order to ensure that generator interconnection facilities are
operated reliably. When implemented, the recommendations included in the Final Report and SARs should go a long way
toward providing the regulatory and compliance certainty needed by generators who own or operate Generator
Interconnection Facilities. Accordingly, Sempra Generation encourages the Standards Drafting Team to act quickly to
implement the SARs.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT.
AmerenUE, Power Operations
Services
The items in Question #7 illustrate the need for a written Agreement or Procedure between the GO, GOP, TO and TOP on
how to comply with these new, and modified, Requirements. An Agreement or Procedure would provide the certainty of:
o Assignable and measurable responsibilities,
o Mutual agreement on specific actions, and
o Implementation deadlines.
Without such an Agreement or Procedure, there will be no auditable commitment to defined specific actions, predetermined
responsibilities and closure of the reliability gap in total.
Response: The SAR DT thanks you for your comment. The SDT will discuss these kinds of issues, but such agreements are covered by the NERC Rules of
Procedures and it is outside the scope of both the SAR DT and the SDT to propose changes to the NERC Rules of Procedure.
ERCOT ISO
The proposed language in Requirements 9 and 10 (hereafter R9 and R10) for NERC Standard TOP-001-X, Reliability
Responsibilities and Authorities, clouds the responsibilities among different functional entities that are and are not held
accountable to this Standard. Specifically, the first part of the sentence in R9 states: “The Generator Operator, in accord with
the expectations defined by the Transmission Operator, shall coordinate...” This statement is overly broad and vague. For
instance, is the statement meant to refer to Interconnection Agreements that have been entered into between Generator
Operators and Transmission Operators? Or, is the statement intended to include other agreements as well? In addition, there
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Question 8 Comment
are items listed in R9 (i.e., switching elements, outage planning, and real-time and anticipated emergency conditions) which
are normally the responsibilities of the Transmission Owner and/or the Reliability Coordinator; however, NERC Standard
TOP-001-X is not applicable to the Transmission Owner or the Reliability Coordinator. Also, the item “other conditions
mutually agreed-upon by the Generator Operator and Transmission Operator” is vague and ambiguous and should be
clarified in order not to confuse tasks that may be more aligned with the responsibilities of the Transmission Owner or the
Reliability Coordinator. Furthermore, R9 and R10 strongly imply and explicitly give the Transmission Operator authority to
take action “in order to preserve Interconnection reliability.” This type of wide-area authority is meant to describe Reliability
Coordinator-related obligations. The NERC Function Reliability Model is clear in defining the function and tasks of reliability
operations. The Reliability Coordinator is responsible, in concert with other Reliability Coordinators, for the Interconnection as
a whole; not the Transmission Operator. Lastly, it is unclear how an entity registered for multiple functions (for example,
Reliability Coordinator and Transmission Operator) would be held accountable under this NERC Standard. If the intent is that
R9 and R10 are to be the obligations only of those functional entities for which the NERC Standard is applicable, then the
language in the NERC Standard should clearly state that intent.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. As envisioned, the SDT will coordinate its work with the Functional Model
Working Group to ensure that any new functional entities are identified with a clear definition, and a clear scope of responsibilities and tasks.
PSEG Companies
The PSEG Companies support this approach to ensure that all components of the BES are adequately covered by the
reliability standards. The drafting team has done a good job of identifying the appropriate areas of concern.
Response: The SAR DT thanks you for your comment.
Transmission Owner/Generation
Owner
The SAR for Project 2010-07 proposes a number of specific changes to existing Reliability Standards based on the GOTO
Report. FPL believes that identifying the exact standards and language for revision should be the purview of a Standards
Drafting Team and not embedded within the SAR itself. The Standards Drafting Team should be empowered to review the
GOTO Report and make independent recommendations. Many of the questions contained in this SAR comment form are
more appropriate for a Standard’s drafting comment form and not for a SAR. The place to discuss and evaluate specific
wording changes as applicable to standards revisions should be contained in the Standard Drafting process. The SAR should
lay the foundation for the need for changes, not disseminate or debate exact changes.FPL would recommend that the
sections “Brief” and “Detailed Description” of the SAR should be amended as follows: “Taking into consideration the GOTO
Final Report from November 2009, the need for revisions to existing standards may exist. The Standards Drafting Team will
evaluate the recommendations of the GOTO Final Report and recommend changes as necessary.”
Response: The SAR DT thanks you for your comment and agrees. The SAR DT has assembled the specific suggestions for revisions to definitions and
requirements provided in response to this SAR. As envisioned, the SDT will consider those comments. Note that the SAR has been modified to give the SDT the
flexibility to address this concern.
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Consideration of Comments on Generator Requirements at the Transmission Interface — Project 2010-07
Organization
Northeast Power Coordinating
Council
Question 8 Comment
The term “two spans” is used in the Introductory Section of this Comment Form (Conclusions Item 6, Recommendations Item
3), and will need a clear, and specific definition. “Generally” is not a word to be used in a definition.
Response: The SAR DT thanks you for your comments.They will be referred to the SDT.
Xcel Energy
There are many other standards development projects underway that are modifying the same standard. It is unclear as to
how the changes will be coordinated amongst the many teams.
Xcel Energy
There are many other standards development projects underway that are modifying the same standard. It is unclear as to
how the changes will be coordinated amongst the many teams.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. As envisioned, the SDT will work with the latest BOT approved versions of
the standards and will coordinate its work with all other SDTs that are actively working on the same standards.
ISO RTO Council Standards
Review Committee
These SAR and associated draft standards changes go beyond what is needed to resolve the GO/TO GOP/TOP registration
issue. The only real changes that are needed are to include adding GO and GOP applicability in the FAC-003 standard so
that vegetation management can be enforced for lines built to interconnect generators without registering the GO/GOP as a
TO/TOP. All additional changes just add confusion and cause significant coordination issues with other draft standard
changes.This proposed SAR and associated standards’ modifications does not appear to have been coordinated with any
other drafting team. There are many standards and requirements that are in various states of change. For instance, the TOP
standards have been significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Midwest ISO Standards
Collaborators
These SAR and associated draft standards changes go beyond what is needed to resolve the GO/TO GOP/TOP registration
issue. The only real changes that are needed are to include adding GO and GOP applicability in the FAC-003 standard so
that vegetation management can be enforced for lines built to interconnect generators without registering the GO/GOP as a
TO/TOP. All additional changes just add confusion and cause significant coordination issues with other draft standard
changes.This proposed SAR and associated standards’ modifications does not appear to have been coordinated with any
other drafting team. There are many standards and requirements that are in various states of change. For instance, the TOP
standards have been significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
Response: The SAR DT thanks you for your comment. It will be referred to the SDT. The purpose of this SAR was to seek stakeholder views on the scope of
requirements that may need modification, and most stakeholders who participated in this comment period support modifications that go beyond modifying only the
Transmission Vegetation Management standard.
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Organization
E.ON U.S.
Question 8 Comment
This SAR should only apply to those separate entity GOPs that already adhere to an OATT. Those GOPs should be required
to register additionally as a TO/TOP. This should not apply to a GOP within a Corporation that includes TO/TOP that adhere
to an OATT, and have already defined an internal division of responsibilities for the Transmission Interface between the GOP
and TOP.
Response: Based on a review of the full body of industry comments, we believe that there is a reliability need for this SAR. Further, registration issues are outside
the scope of the SAR DT.
Energy Standards Working
Group
We commend the work of the team that produced the report and this SAR and suggest that the Standard Drafting Team give
due deference to the report with the modifications that we have suggested in questions 4 and 5 above.In addition, EPSA
would highlight the following conclusions that follow from the report:
oThe Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility
oA Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator
oAfter review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators, no
existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility
Response: The SAR DT thanks you for your comment. The SAR DT agrees with your conclusions.
Tenaska, Inc.
We commend the work of the team that produced the report and this SAR and suggest that the Standard Drafting Team give
due deference to the report with the modifications that we have suggested in questions 4 and 5 above.In addition, we would
highlight the following conclusions that follow from the report:
o The Generator Owner or Generator Operator that owns and/or operates a Generator Interconnection Facility, that is, a soleuse facility that interconnects the generator to the grid, should not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility
o A Generator Interconnection Facility is considered as though part of the generating facility specifically for purposes of
applying Reliability Standards to a Generator Owner or Generator Operator
o After review of the existing Transmission Operator requirements that are not currently applicable to Generator Operators,
no existing Transmission Operator requirements should apply to Generator Operators as a result of the Generator
Interconnection Facility
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Question 8 Comment
Response: The SAR DT thanks you for your comment. The SAR DT agrees with your conclusions.
88
Project 2010-07: Generator
Requirements at the
Transmission Interface
White Paper Proposal for Informal Comment
March 2011
Table of Contents
Introduction ..................................................................................................................................... 2
Objective ......................................................................................................................................... 2
Proposed Next Steps and Review of Reliability Standards ............................................................ 4
Summary and Discussion of Other Solutions ................................................................................. 7
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
1
Project 2010-07:
Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
Introduction
The Bulk Electric System 1 consists of many parts, including power plants and transmission
facilities. While most transmission facilities operate as part of the overall integrated grid, a
number of transmission facilities operate more like an extension cord to interconnect power
plants and loads to the bulk power system. 2 These transmission facilities that connect power
plants to the integrated grid are commonly known as generator interconnection facilities.
Power plants, and their respective pieces and parts, come in all sizes and configurations. Some
plants consist of just a single generating unit, other plants consist of multiple generating units,
and still others consist of multiple generating units spread over several thousand acres. While
not all power plants are considered part of the Bulk Electric System, ultimately, all the plants are
interconnected to the bulk power system via their generator interconnection facilities. Of
concern is how to classify all such generating facilities, including their generator interconnection
facilities, to determine what level of reliability is needed for such facilities.
Objective
The purpose of Project 2010-07—Generator Requirements at the Transmission Interface is to
ensure that all generator-owned Facilities 3 that are considered part of the Bulk Electric System
are identified and that the level of reliability needed to operate such Facilities is appropriately
covered under NERC’s Reliability Standards. This will be accomplished by proposing a set of
changes to existing standard requirements, introducing new requirements, and, if necessary,
modifying definitions of some NERC-defined terms. The collective efforts will add clarity to
Generator Owners and Generator Operators regarding their reliability standard obligations at the
interface with the integrated bulk power system.
Since the formation of the Project 2010-07 Standard Drafting Team (SDT) in December 2010,
the SDT has focused on reworking the Generator Requirements at the Transmission Interface Ad
Hoc Group’s 4 (GOTO Ad Hoc Group) original proposed plan for addressing generator
1
The current definition of “Bulk Electric System” in the NERC’s Glossary of Terms reads: “As defined by the
Regional Reliability Organization, the electrical generation resources, transmission lines, interconnections with
neighboring systems, and associated equipment, generally operated at voltages of 100 kV or higher. Radial
transmission facilities serving only load with one transmission source are generally not included in this definition.”
This definition is undergoing significant revision under Project 2010-17—Definition of Bulk Electric System.
2
This paper uses the term “bulk power system” as it is defined in Section 215 of the Federal Power Act: “(A)
facilities and control systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof); and (B) electric energy from generation facilities needed to maintain transmission system
reliability. The term does not include facilities used in the local distribution of electric energy.”
3
“Facility” is defined in NERC’s Glossary of Terms as “A set of electrical equipment that operates as a single Bulk
Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.).”
4
NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in 2009 to analyze and
make recommendations for establishing general criteria for determining whether Generator Owners and Generator
Operators should be registered for Transmission Owner and Transmission Operator requirements in NERC’s
Reliability Standards.
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
2
requirements at the transmission interface. Based on feedback from the industry, along with
input from NERC and FERC staffs, the GOTO Ad Hoc Group made a series of
recommendations that included changes to various reliability standards, the modification of
existing definitions, and the creation of some new definitions. However, based on more recent
feedback from industry and regulators, and after taking into account other standards projects
under development, the SDT decided that the plan of proposing new definitions, modifying other
definitions, and making changes to dozens of standards was no longer necessary.
The SDT believes it is appropriate to classify various generating Facilities and Elements
(including generator interconnection facilities) as part of the Bulk Electric System. The SDT
also believes that qualifying generator interconnection facilities should be classified as
transmission. That does not mean, however, that a Generator Owner or Generator Operator
should be required to automatically register as a Transmission Owner or Transmission Operator
simply because it owns and/or operates transmission Elements or Facilities. While qualifying
Generator Owners and Generator Operators can be classified as owning and operating electric
transmission Elements and Facilities, these are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.
Requiring any classification that subjects Generator Owners and Generator Operators to all the
standards applicable to Transmission Owners and Transmission Operators would do little, if
anything, to improve the reliability of the Bulk Electric System. When the transmission
Elements and Facilities owned and operated by Generator Owners and Generator Operators are
non-network/non-integrated transmission, applying all standards applicable to Transmission
Owners and Transmission Operators would have little effect on the overall reliability of the Bulk
Electric System when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.
To maintain an adequate level of reliability in the Bulk Electric System, a clear delineation of
responsibilities and authority at the interface between Generator Owners/Operators and
Transmission Owners/Operators is needed. This can be accomplished by properly applying
selected standards or specific standard requirements to Generator Owners and Generator
Operators. The SDT is recommending a plan to modify the Purpose, the Functional Entity
section, requirements, and measures of a selected group of standards to make them applicable to
Generator Owners and Generator Operators, and to add clarity to such standards regarding
generator interconnection facilities.
Note that at this stage in its work, the SDT has made no final decisions on its proposed plan;
rather, it is seeking informal feedback from the industry regarding its assumptions and
recommendations. Throughout the informal comment stage, the SDT plans to rely heavily on
this informal input and feedback to lessen the need to expend limited industry resources on
developing specific and exacting standards changes. At this informal stage, the SDT has not
developed definitional changes, VSLs, VRFs, Implementation Plans, etc. for its proposed
changes; those will be developed as needed once the project progresses further and proposed
changes are finalized.
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
3
Proposed Next Steps and Review of Reliability Standards
The Project 2010-07 Standard Drafting Team (SDT) proposes the following recommendations to
clearly identify the appropriate generation Facilities and the standards requirements that should
apply to such generation Facilities to ensure that the reliability of the Bulk Electric System is
maintained:
1. Add “Generator Owner” to the Applicability section of FAC-001-0 and add a
requirement and a measure to address the responsibilities specific to the Generator
Owner.
FAC-001-0—Facility Connection Requirements currently applies to Transmission
Owners and addresses the need for Transmission Owners to establish facility connection
and performance requirements. While the standard requires Transmission Owners to
address connection requirements for “generation facilities, transmission facilities, and
end-user facilities,” it does not address the requirements for a Generator Owner that has
received a request for interconnection. The lack of such requirements for a Generator
Owner’s Facility could result in gaps.
Therefore, the SDT proposes that “Generator Owner” be added to the Applicability
section of FAC-001-0. It further proposes the addition of Requirement 4 and a
corresponding measure:
R4. Generator Owner that receives an interconnection request for its facility
shall, within 45 days of such a request, be required to comply with
requirements R1, R2, and R3 for the facility for which it received the
interconnection request.
M4. The Generator Owner that receives an interconnection request for its facility
shall make available (to its Compliance Monitor) for inspection evidence that
it met the requirements stated in Reliability Standard FAC-001-0 R4.
These proposed standard changes are redlined in Attachment 1.
Note that FAC-001-0 has been assigned for modification under Project 2010-02, but as of
March 4, 2011, no activity has yet taken place on that project.
2. Add “Generator Owner” to the Applicability section of FAC-003-2 and modify the
requirements and measures to include Generator Owner.
The proposed FAC-003-2 currently applies to Transmission Owners and addresses the
need to maintain a reliable electric transmission system by using a defense-in-depth
strategy to manage vegetation located on transmission rights of way (ROW) and
minimize encroachments from vegetation located adjacent to the ROW.
A Transmission Vegetation Management Plan is used to ensure the reliable operation of
electric transmission systems and prevent vegetation-related outages. Because generatorowned Facilities may include electric transmission, FAC-003-2 should be applicable to
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
4
Generator Owners. Requiring Generator Owners to adhere to the requirements in this
standard will ensure that Facilities like the generator interconnecting line lead are
inspected as defined in the Transmission Vegetation Management Plan and that all
vegetation that breaches specified clearances is properly trimmed. This change in
applicability will also ensure the proper reporting of vegetation-related outages to the
appropriate Regional Reliability Organizations.
The SDT proposes that “Generator Owner” is added to all requirements and measures
that mention the Transmission Owner. These proposed changes are outlined in
Attachment 2.
The SDT recognizes that if these standard changes are made, changes to the
accompanying FAC-003-2 definition modifications may also be needed. As noted above,
such changes will be considered after informal comments are received.
3. Follow the Project 2010-17—Definition of Bulk Electric System and ensure that the
responsibility for generator interconnecting line leads is appropriately and clearly
assigned to Generator Owners and Operators.
The Project 2010-07 SDT recognizes that it cannot control the work of the SDT working
on the definition of Bulk Electric System. Still, the Project 2010-07 SDT is hopeful that
changes made to this definition will be instrumental in covering the reliability gap with
respect to generator requirements at the transmission interface. At this stage in the
definition’s development, Project 2010-17’s concept paper has a section on Proposed
BES Criteria, and it includes the following:
3. Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s)) with aggregate capacity greater than 75 MVA
(gross nameplate rating) directly connected via a step-up transformer(s) to
Transmission Facilities operated at voltages of 100 kV or above;
The Project 2010-07 SDT recognizes that this concept paper is a working draft and is in
no way enforceable at this time; still, the Project 2010-07 SDT is hopeful that the BES
team is moving in a direction that will be complementary to its own work.
The proposed changes listed above mark a significant decrease in changes originally proposed by
the GOTO Ad Hoc Group in its Final Report. In particular, clarifications to the definition of
Bulk Electric System eliminate the need for the GOTO Ad Hoc Group’s suggestions to include a
reference to the proposed new term “Generator Interconnection Facility” in the following
standards referenced in the GOTO Ad Hoc Group Final Report:
•
•
•
•
•
•
BAL-005-0.1b
CIP-002-1
EOP-001-0
EOP-004-1
FAC-008-1
FAC-009-1
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
5
•
•
•
•
•
•
•
•
•
IRO-005-2
MOD-010-0
MOD-012-0
PRC-004-1
PRC-005-1
TOP-002-2
TOP-003-0
VAR-001-1
VAR-002-1
All of the standards listed above already apply to the Generator Owner or Generator Operator, 5
so as long as generator-owned Facilities like generator interconnection facilities are
appropriately assigned to the responsibility of those entities with changes to the definition of
Bulk Electric System, there should be no need to highlight the inclusion of “Generator
Interconnection Facility” with language changes in those standards.
Other proposed changes are also unnecessary. In EOP-003-1, the GOTO Ad Hoc Group had
originally proposed that Generator Operators be added to the requirement that requires
Transmission Operators and Balancing Authorities to coordinate automatic load-shedding
throughout their areas. The SDT determined that this addition was unnecessary because PRC001 already includes the requirement that Transmission Operators coordinate their UFLS
programs with underfrequency isolation of generating units, which infers that Generator
Operators need to provide their underfrequency settings to their respective Transmission
Operator. Further, Generator Operators should not be involved in the high-level coordination
that this standard requires.
In EOP-008-0, the proposed reference to the Generator Interconnection Operational Interface
can be eliminated because the proposed term was meant to consist of Elements and Facilities
rated at 100 kV and above, which the team has acknowledged are transmission.
In the cases of PER-001-0 and PER-002-0, the SDT believes that additional requirements for
training of Generator Owner and Generator Operator personnel should be addressed in a future
project. In FERC Order 693, a directive applied “to generator operator personnel at a centrallylocated dispatch center who receive direction and then develop specific dispatch instructions for
plant operators under their control.” FERC directed that those Generator Operator personnel
receive formal training of the nature provided to system operators under PER-005-1. FERC
Order 742 confirms that the Commission has “not modified the scope of applicability of the
Order 693 directive regarding generator operator training.”
The SDT has also considered proposing further modifications to PRC-001-2 to ensure
coordination of protection system information among Generator Operators and Transmission
Operators and to standards TOP-001-2, and TOP-003-2 (all of which are currently under
development) to ensure that coordination of information among Generator Operators and
Transmission Operators. The SDT has consulted with the members of the Project 2007-03—
5
Many have also changed significantly since the GOTO Ad Hoc Group’s review.
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
6
Real-time Operations SDT and believes that the necessary level of coordination (including for
Special Protection Systems) is covered by the requirements in the proposed new TOP-003-2.
In TOP-004-2, the GOTO Ad Hoc Group’s addition of R7 (requiring the Generator Operator to
operate its generator interconnection facility within its applicable ratings) is not needed because
existing TOP and IRO standards require entities to operate within, or to mitigate, SOLs and
IROLs at the direction of the TOP and RC.
The proposed addition of R5 to TOP-008-1 is also unnecessary because it will be covered in the
data specifications of TOP-003-2, R1. (TOP-008 is being retired.)
Summary and Discussion of Other Solutions
Again, the purpose of this project is to clearly identify the appropriate generation Facilities and
the standards requirements that should apply to such generation Facilities to ensure that the
reliability of the Bulk Electric System is maintained. The SDT recognizes that its work alone
may not eliminate all reliability gaps with respect to generator-owned Facilities like generator
interconnection facilities. As noted above, Project 2010-17—Definition of Bulk Electric System
may have an enormous impact on the work of this SDT. We are confident that these changes we
have proposed to a small number of standards, in coordination with changes to the Bulk Electric
System definition, can achieve the necessary reliability, but we also acknowledge that many
entities have taken advantage of solutions outside the standards process that have achieved the
same effect.
On April 20, 2010, NERC Compliance published a Public Bulletin to provide guidance for
situations like this, in which entities delegate reliability tasks to a third-party entity. In this
bulletin, NERC Compliance emphasizes that while a registered entity may not delegate its
responsibility for ensuring that a task is completed, it may delegate the performance of a task to
another entity.
As is explained in the bulletin, compliance responsibility for applicable NERC Reliability
Standard requirements and accountability for violations thereof may be achieved through several
means, including the following:
1. By Individual: an entity is registered on the NERC Compliance Registry and such
registered entity assumes full compliance responsibility and accountability; or
2. By Written Contract: parties enter into written agreement whereby:
a. A registered entity delegates the performance of some or all functional activities
to a third party that is not a registered entity, and the registered entity retains full
compliance responsibility and violation accountability; or
b. A registered entity delegates the performance of some or all of the functional
activities to a third party, and the third party accepts full compliance
responsibility for the specific functions it performs and violation accountability.
In this case, there may be individual, concurrent or joint registration of the
entities, depending on the nature of the contractual relationship and, in any event,
only the registered entity would be held responsible or accountable by a Regional
Entity or NERC; or
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
7
3. By Joint Registration Organization (JRO): each party is registered and is required to
clearly identify and allocate compliance responsibility and violation accountability for
their respective functions under applicable NERC Reliability Standard requirements.
Because the standards efforts outlined here will not take effect for a year or more, Generator
Owners and Generator Operators that are concerned about their registration status should explore
options like those explained above and in further detail in NERC Compliance Bulletin 2010-004.
The Project 2010-07 SDT will continue with the efforts outlined above, but will modify its
proposal and ultimate actions based on feedback from the industry.
Project 2010-07: Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment
March 2011
8
Attachment 1
Standard FAC-001-0 — Facility Connection Requirements
A.
Introduction
1.
Title:
Facility Connection
Requirements
2.
Number:
3.
Purpose: To avoid adverse impacts on
reliability, Transmission Bulk Electric
System Facility Oowners must establish
facility connection and performance requirements.
4.
Transmission Owner
4.1.4.2.
5.
FAC-001-0
Applicability:
4.1.
B.
Note from the Project 2010-07 SDT: The redline
changes included in this document are the work of
the Project 2010-07 SDT and are provided as a
companion to the team’s White Paper; the aim is to
provide an example to convey the direction of our
proposal. This is not intended to be a comprehensive
rewrite of the standard.
Generator Owner
Effective Date:
April 1, 2005
Requirements
R1. The Transmission Owner shall document, maintain, and publish facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability Organization, subregional, Power Pool, and individual Transmission Owner
planning criteria and facility connection requirements. The Transmission Owner’s facility
connection requirements shall address connection requirements for:
R1.1. Generation facilities,
R1.2. Transmission facilities, and
R1.3. End-user facilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
R2.1. Provide a written summary of its plans to achieve the required system performance
as described above throughout the planning horizon:
R2.1.1. Procedures for coordinated joint studies of new facilities and their impacts
on the interconnected transmission systems.
R2.1.2. Procedures for notification of new or modified facilities to others (those
responsible for the reliability of the interconnected transmission systems) as
soon as feasible.
R2.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
R2.1.4. Breaker duty and surge protection.
R2.1.5. System protection and coordination.
R2.1.6. Metering and telecommunications.
R2.1.7. Grounding and safety issues.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
1 of 3
Attachment 1
Standard FAC-001-0 — Facility Connection Requirements
R2.1.8. Insulation and insulation coordination.
R2.1.9. Voltage, Reactive Power, and power factor control.
R2.1.10. Power quality impacts.
R2.1.11. Equipment Ratings.
R2.1.12. Synchronizing of facilities.
R2.1.13. Maintenance coordination.
R2.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15. Inspection requirements for existing or new facilities.
R2.1.16. Communications and procedures during normal and emergency operating
conditions.
R3. The Transmission Owner shall maintain and update its facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements
available to the users of the transmission system, the Regional Reliability Organization, and
NERC on request (five business days).
R4. Generator Owner that receives an interconnection request for its facility shall, within 45 days
of such a request, be required to comply with requirements R1, R2, and R3 for the facility for
which it received the interconnection request.
Formatted: Indent: Left: 0.35", No bullets or
numbering
R3.
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R1.
M2. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all requirements stated in Reliability Standard FAC-001-0_R2.
M3. The Transmission Owner shall make available (to its Compliance Monitor) for inspection
evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R3.
M3.M4. The Generator Owner that receives an interconnection request for its facility shall make
available (to its Compliance Monitor) for inspection evidence that it met the requirements
stated in Reliability Standard FAC-001-0 R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
1.2.
Compliance Monitoring Period and Reset Timeframe
On request (five business days).
1.3.
Data Retention
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
2 of 3
Attachment 1
Standard FAC-001-0 — Facility Connection Requirements
None specified.
1.4.
2.
E.
Additional Compliance Information
None.
Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
3 of 3
Attachment 2
FAC-003-2 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during
the development of the standard and will be removed
when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11,
2007).
2. SAR posted for comment (January 15–February
14, 2007).
3. SAR posted for comment (April 10–May 9,
2007).
4. SC authorized moving the SAR forward to
standard development (June 27, 2007).
Note from the Project 2010-07 SDT:
The redline changes included in this
document are the work of the
Project 2010-07 SDT and are
provided as a companion to the
team’s White Paper; the aim is to
provide an example to convey the
direction of our proposal. This is not
intended to be a comprehensive
rewrite of the standard. Any formal
standard revision would require
coordination with the work of the
drafting team currently revising
FAC-003-2 under Project 2007-07.
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Forth draft of revised standard posted (June 17, 2010-July 17, 2010).
Proposed Action Plan and Description of Current Draft
This is the third posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the fifth draft overall.
Future Development Plan
Anticipated Actions
Anticipated Date
Recirculation ballot of standards.
January 2011
Receive BOT approval
February 2011
Draft 5: January 27, 2011
1
Attachment 2
FAC-003-2 — Transmission Vegetation Management
Effective Dates
First calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities where such explicit approval
is required.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of an
IROL or as a Major WECC transfer path, becomes subject to this standard 12 months after
the date the Planning Coordinator or WECC initially designates the line as being subject to
this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an asset
owner and was not previously subject to this standard, becomes subject to this standard 12
months after the acquisition date of the line.
Draft 5: January 27, 2011
2
Attachment 2
FAC-003-2 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
Draft 5: January 27, 2011
Regulatory Approval — Effective Date
New
3
FAC-003-2 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n d a rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s
legal rights but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
Draft 5: December 17, 2010
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
4
FAC-003-2 — Transmission Vegetation Management
In tro d u c tio n
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-2
3. Objectives:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1. Functional Entities:
Transmission Owners
Formatted: Normal, Indent: Left: 0", Space
After: 0 pt, Tab stops: Not at 1.13"
Generator Owners
4.2. Facilities: Defined below (referred to as “applicable lines”), including but not limited
to those that cross lands owned by federal 1, state, provincial, public, private, or tribal
entities:
4.2.1.
Overhead transmission lines operated at 200kV or higher.
4.2.2.
Overhead transmission lines operated below 200kV having been identified as
included in the definition of an Interconnection Reliability Operating Limit
(IROL) under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3.
Overhead transmission lines
operated below 200 kV having
been identified as included in the
definition of one of the Major
WECC Transfer Paths in the Bulk
Electric System.
4.2.4.
1
This standard applies to overhead
transmission lines identified above
(4.2.1 through 4.2.3) located
outside the fenced area of the
switchyard, station or substation
and any portion of the span of the
transmission line that is crossing
the substation fence.
Rationale
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
as follows: 1) There is a very low risk from
vegetation in this area. Based on an informal
survey, no TOs reported such an event. 2)
Substations, switchyards, and stations have many
inspection and maintenance activities that are
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 4) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 5: December 17, 2010
5
FAC-003-2 — Transmission Vegetation Management
4.3. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard. [Straw proposal]
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Right-of-Way, vandalism, human activities and acts of nature. Operating
experience indicates that trees that have grown out of specification have contributed to
Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
Draft 5: December 17, 2010
6
FAC-003-2 — Transmission Vegetation Management
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 5: December 17, 2010
7
FAC-003-2 — Transmission Vegetation Management
Re q u ire m e n ts a n d Me a s u re s
R1. Each Transmission Owner and Generator
Rationale
Owner shall manage vegetation to prevent
The MVCD is a calculated minimum
encroachments of the types shown below, into
distance stated in feet (meters) to prevent
the Minimum Vegetation Clearance Distance
flash-over between conductors and
(MVCD) of any of its applicable line(s)
vegetation, for various altitudes and
identified as an element of an Interconnection
operating voltages. The distances in Table 2
Reliability Operating Limit (IROL) in the
were derived using a proven transmission
planning horizon by the Planning Coordinator;
design method. The types of failure to
or Major Western Electricity Coordinating
manage vegetation are listed in order of
Council (WECC) transfer path(s); operating
increasing degrees of severity in nonwithin its Rating and all Rated Electrical
compliant performance as it relates to a
Operating Conditions.2
failure of a TO’s vegetation maintenance
1. An encroachment into the MVCD as
program since the encroachments listed
shown in FAC-003-Table 2, observed in
require different and increasing levels of
Real-time, absent a Sustained Outage,
skills and knowledge and thus constitute a
2. An encroachment due to a fall-in from
logical progression of how well, or poorly, a
inside the Right-of-Way (ROW) that
TO manages vegetation relative to this
caused a vegetation-related Sustained
Requirement.
Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each Transmission Owner and Generator Owner has evidence that it managed
vegetation to prevent encroachment into the MVCD as described in R1. Examples of
acceptable forms of evidence may include dated attestations, dated reports containing
no Sustained Outages associated with encroachment types 2 through 4 above, or
records confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner or Generator Owner
shows that a vegetation encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the equivalent of a Real-time
observation.
2
This requirement does not apply to circumstances that are beyond the control of a Transmission Owner or
Generator Owner subject to this reliability standard, including natural disasters such as earthquakes, fires, tornados,
hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner, the
Generator Owner, or an applicable regulatory body, ice storms, and floods and; human or animal activity such as
logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural
activities, or removal or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
Draft 5: December 17, 2010
8
FAC-003-2 — Transmission Vegetation Management
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
R2. Each Transmission Owner and Generator
Owner shall manage vegetation to prevent
encroachments of the types shown below, into
the MVCD of any of its applicable line(s) that
is not an element of an IROL; or Major WECC
transfer path; operating within its Rating and
all Rated Electrical Operating Conditions.2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the ROW that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that
caused a vegetation-related Sustained
Outage.
[VRF – Medium] [Time Horizon – Real-time]
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of a TO’s vegetation maintenance
program since the encroachments listed
require different and increasing levels of
skills and knowledge and thus constitute a
logical progression of how well, or poorly,
a TO manages vegetation relative to this
Requirement.
M2. Each Transmission Owner and Generator Owner has evidence that it managed
vegetation to prevent encroachment into the MVCD as described in R2. Examples of
acceptable forms of evidence may include dated attestations, dated reports containing
no Sustained Outages associated with encroachment types 2 through 4 above, or
records confirming no Real-time observations of any MVCD encroachments.
If a later confirmation of a Fault by the Transmission Owner or Generator Owner
shows that a vegetation encroachment within the MVCD has occurred from
vegetation within the ROW, this shall be considered the equivalent of a Real-time
observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
Draft 5: December 17, 2010
9
FAC-003-2 — Transmission Vegetation Management
R3. Each Transmission Owner and Generator
Rationale
Owner shall have documented maintenance
The documentation provides a basis for
strategies or procedures or processes or
evaluating the competency of the
specifications it uses to prevent the
Transmission Owner’s vegetation program.
encroachment of vegetation into the MVCD
There may be many acceptable approaches
of its applicable transmission lines that
to maintain clearances. Any approach must
include(s) the following:
demonstrate that the Transmission Owner
3.1 Accounts for the movement of
avoids vegetation-to-wire conflicts under all
applicable transmission line conductors
Rated Electrical Operating Conditions. See
under their Facility Rating and all Rated
Figure 1 for an illustration of possible
Electrical Operating Conditions;
conductor locations.
3.2 Accounts for the inter-relationships
between vegetation growth rates,
vegetation control methods, and inspection frequency.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the Transmission Owner or Generator Owner can prevent
encroachment into the MVCD considering the factors identified in the requirement.
(R3)
R4. Each Transmission Owner and Generator
Rationale
Owner, without any intentional time delay,
To ensure expeditious communication between
shall notify the control center holding
the Transmission Owner and the control center
switching authority for the associated
when a critical situation is confirmed.
applicable transmission line when the
Transmission Owner or Generator Owner
has confirmed the existence of a vegetation
condition that is likely to cause a Fault at any moment.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each Transmission Owner and Generator Owner that has a confirmed vegetation
condition likely to cause a Fault at any moment will have evidence that it notified the
control center holding switching authority for the associated transmission line without
any intentional time delay. Examples of evidence may include control center logs,
voice recordings, switching orders, clearance orders and subsequent work orders.
(R4)
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10
FAC-003-2 — Transmission Vegetation Management
R5. When a Transmission Owner or Generator
Owner is constrained from performing
vegetation work, and the constraint may lead
to a vegetation encroachment into the MVCD
of its applicable transmission lines prior to the
implementation of the next annual work plan
then the Transmission Owner or Generator
Owner shall take corrective action to ensure
continued vegetation management to prevent
encroachments.
[VRF – Medium] [Time Horizon – Operations
Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
Transmission Owner from performing
planned vegetation maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the Transmission Owner to put interim
measures in place, rather than do nothing.
The corrective action process is intended to
address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
M5. Each Transmission Owner and
Generator Owner has evidence of the corrective action taken for each constraint
where an applicable transmission line was put at potential risk. Examples of
acceptable forms of evidence may include initially-planned work orders,
documentation of constraints from landowners, court orders, inspection records of
increased monitoring, documentation of the de-rating of lines, revised work orders,
invoices, and evidence that a line was de-energized. (R5)
R6. Each Transmission Owner and Generator
Owner shall perform a Vegetation Inspection
of 100% of its applicable transmission lines
(measured in units of choice - circuit, pole
line, line miles or kilometers, etc.) at least
once per calendar year and with no more than
18 months between inspections on the same
ROW. 3
[VRF – Medium] [Time Horizon – Operations
Planning]
M6. Each Transmission Owner and
Generator Owner has evidence that it
conducted Vegetation Inspections of the
transmission line ROW for all applicable
Rationale
Inspections are used by Transmission
Owners to assess the condition of the entire
ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
recently-completed work. This requirement
sets a minimum Vegetation Inspection
frequency of once per calendar year but
with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America
and on common utility practice, this
minimum frequency is reasonable.
Transmission Owners should consider local
and environmental factors that could
warrant more frequent inspections.
3
When the Transmission Owner or Generator Owner is prevented from performing a Vegetation Inspection within
the timeframe in R6 due to a natural disaster, the Transmission Owner or Generator Owner is granted a time
extension that is equivalent to the duration of the time the Transmission Owner or Generator Owner was prevented
from performing the Vegetation Inspection.
Draft 5: December 17, 2010
11
FAC-003-2 — Transmission Vegetation Management
transmission lines at least once per calendar year but with no more than 18 months
between inspections on the same ROW. Examples of acceptable forms of evidence
may include completed and dated work orders, dated invoices, or dated inspection
records. (R6)
R7. Each Transmission Owner and Generator
Rationale
Owner shall complete 100% of its annual
This requirement sets the expectation that
vegetation work plan to ensure no vegetation
the work identified in the annual work plan
encroachments occur within the MVCD.
will be completed as planned. An annual
Modifications to the work plan in response to
vegetation work plan allows for work to be
changing conditions or to findings from
modified for changing conditions, taking
vegetation inspections may be made (provided
into consideration anticipated growth of
they do not put the transmission system at risk
vegetation and all other environmental
of a vegetation encroachment) and must be
factors, provided that the changes do not
documented. The percent completed
violate the encroachment within the MVCD.
calculation is based on the number of units
actually completed divided by the number of
units in the final amended plan (measured in units of choice - circuit, pole line, line miles
or kilometers, etc.) Examples of reasons for modification to annual plan may include:
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of a Transmission Owner or Generator
Owner 4
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
• Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each Transmission Owner and Generator Owner has evidence that it completed its annual
vegetation work plan. Examples of acceptable forms of evidence may include a copy of the
completed annual work plan (including modifications if any), dated work orders, dated invoices,
or dated inspection records. (R7)
4
Circumstances that are beyond the control of a Transmission Owner or Generator Owner include but are not
limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either
by the TO or GO or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural
activities.
Draft 5: December 17, 2010
12
FAC-003-2 — Transmission Vegetation Management
Co m p lia n c e
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The Transmission Owner retains data or evidence to show compliance with Requirements
R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and M7 for three calendar years
unless directed by its Compliance Enforcement Authority to retain specific evidence for a
longer period of time as part of an investigation.
The Transmission Owner retains data or evidence to show compliance with Requirement R4,
Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice
recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an investigation.
If a Transmission Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of
applicable transmission lines determined by the Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, which includes as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the Transmission Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
Draft 5: December 17, 2010
13
FAC-003-2 — Transmission Vegetation Management
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
o Category 4B — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
The Regional Entity will report the outage information provided by Transmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a
result of any of the reported Sustained Outages.
Draft 5: December 17, 2010
14
FAC-003-2 — Transmission Vegetation Management
Tim e Horizo ns , Viola tio n Ris k Fa c tors , a n d Viola tio n S e ve rity Le ve ls
Table 1
R#
R1
Time
Horizon
Real-time
R2
Real-time
R3
Long-Term
Planning
VRF
Violation Severity Level
Lower
Moderate
High
Severe
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
High
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The Transmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
Medium
The
Transmission
Owner had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Owner has
maintenance strategies or documented
procedures or processes or
specifications but has not accounted for
the inter-relationships between
The Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for the
The Transmission Owner does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent the
Lower
Draft 5: December 17, 2010
15
FAC-003-2 — Transmission Vegetation Management
vegetation growth rates, vegetation
control methods, and inspection
frequency, for the Transmission
Owner’s applicable lines.
R4
R5
R6
Real-time
Operations
Planning
Operations
Planning
Medium
movement of transmission
line conductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
Transmission Owner’s
applicable lines.
encroachment of vegetation into
the MVCD, for the Transmission
Owner’s applicable lines.
The Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
transmission line, but there
was intentional delay in that
notification.
The Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center holding
switching authority for that
transmission line.
The Transmission Owner did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
The
Transmission
Owner failed
to inspect 5%
or less of its
applicable
transmission
lines
(measured in
units of
choice circuit, pole
line, line
miles or
Draft 5: December 17, 2010
The Transmission Owner failed to
inspect more than 5% up to and
including 10% of its applicable
transmission lines (measured in units
of choice - circuit, pole line, line miles
or kilometers, etc.).
The Transmission Owner
failed to inspect more than
10% up to and including 15%
of its applicable transmission
lines (measured in units of
choice - circuit, pole line, line
miles or kilometers, etc.).
16
The Transmission Owner failed
to inspect more than 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
FAC-003-2 — Transmission Vegetation Management
kilometers,
etc.)
R7
Operations
Planning
Medium
The
Transmission
Owner failed
to complete
up to 5% of
its annual
vegetation
work plan
(including
modifications
if any).
Draft 5: December 17, 2010
The Transmission Owner failed to
complete more than 5% and up to 10%
of its annual vegetation work plan
(including modifications if any).
The Transmission Owner
failed to complete more than
10% and up to 15% of its
annual vegetation work plan
(including modifications if
any).
17
The Transmission Owner failed
to complete more than 15% of its
annual vegetation work plan
(including modifications if any).
FAC-003-2 — Transmission Vegetation Management
Va ria n c e s
None.
In te rp re ta tio n s
None.
Draft 5: December 17, 2010
18
FAC-003-2 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to
prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of
transmission lines. R1 is applicable to lines “identified as an element of an Interconnection
Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council (WECC)
transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a
Sustained Outage”. R2 applies to all other applicable lines that are not an element of an IROL or
Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related
encroachment resulting in a Sustained Outage due to blowing together of applicable lines and
vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of a Fault by a Transmission Owner confirms that a
vegetation encroachment within the MVCD occurred, then it shall be considered the equivalent
of a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of a Transmission Owner to manage vegetation and to the corresponding performance
level of the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with a
Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading
Draft 5: December 17, 2010
19
FAC-003-2 — Transmission Vegetation Management
event. The additional benefits of such a combination are that it simplifies the standard and clearly
defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the
overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb may only partially break and intermittently contact a conductor. Such events are
considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, a Transmission Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the Transmission System. The approach provides the basis for
evaluating the intent, allocation of appropriate resources and the competency of the Transmission
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the Transmission Owner must be able to state what its
approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach a
Transmission Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 5: December 17, 2010
20
FAC-003-2 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4
involves the notification of potentially threatening vegetation conditions, without any intentional
delay, to the control center holding switching authority for that specific transmission line.
Examples of acceptable unintentional delays may include communication system problems (for
example, cellular service or two-way radio disabled), crews located in remote field locations
with no communication access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of a Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation
reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
The Transmission Owner has the responsibility to ensure the proper communication between
field personnel and the control center to allow the control center to take the appropriate action
until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in
the line loading, switching the line out of service, or positioning the system in recognition of the
increasing risk of outage on that circuit. The notification of the threat should be communicated in
terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
Draft 5: December 17, 2010
21
FAC-003-2 — Transmission Vegetation Management
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission Owners may have a danger tree identification
program that identifies trees for removal with the potential to fall near the line. These trees
would not require notification to the control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained
from performing vegetation maintenance. The intent of this requirement is to deal with situations
that prevent the Transmission Owner from performing planned vegetation management work
and, as a result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or
other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to
take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission Owner is required to take an interim corrective action to mitigate the potential
risk to the transmission line. A wide range of actions can be taken to address various situations.
General considerations include:
•
•
•
•
•
Identifying locations where the Transmission Owner is constrained from performing
planned vegetation maintenance work which potentially leaves the transmission line
at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission Owner could consider location specific measures such as modifying
the inspection and/or maintenance intervals. Where a legal constraint would not allow
any vegetation work, the interim corrective action could include limiting the loading
on the transmission line.
The Transmission Owner should document and track the specific corrective action
taken at each location. This location may be indicated as one span, one tree or a
combination of spans on one property where the constraint is considered to be
temporary.
Draft 5: December 17, 2010
22
FAC-003-2 — Transmission Vegetation Management
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates a
Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line
miles, ROW miles, etc.
For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this
Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission
lines at least once during the calendar year. If one of the included lines was 100 miles long, and
if it was not inspected during the year, then the amount failed to inspect would be 100/2000 =
0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The Transmission Owner is required to implement an annual
work plan for vegetation management to accomplish the purpose of this standard. Modifications
to the work plan in response to changing conditions or to findings from vegetation inspections
may be made and documented provided they do not put the transmission system at risk. The
annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that
the Transmission Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the Transmission Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent
line inspections may identify unanticipated high priority work, weather conditions (drought)
could make herbicide application ineffective during the plan year, or a major storm could require
redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the Transmission
Owner’s system to work on another system. Any of these examples could result in acceptable
deferrals or additions to the annual work plan. Modifications to the annual work plan must
always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive
approach that exercises the full extent of legal rights on the ROW is superior to incremental
Draft 5: December 17, 2010
23
FAC-003-2 — Transmission Vegetation Management
management in the long term because it reduces the overall potential for encroachments, and it
ensures that future planned work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal
lands. In some cases the lead time for obtaining permits may necessitate preparing work plans
more than a year prior to work start dates. Transmission Owners may also need to consider those
special landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the Transmission
Owner, evidence of successful annual work plan execution could consist of signed-off work
orders, signed contracts, printouts from work management systems, spreadsheets of planned
versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence
may include photographs, and walk-through reports.
Draft 5: December 17, 2010
24
FAC-003-2 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)
5
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
5
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially
greater distances will be achieved at time of vegetation maintenance.
Draft 5: December 17, 2010
25
FAC-003-2 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
Draft 5: December 17, 2010
26
FAC-003-2 — Transmission Vegetation Management
•
•
•
avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
transmission lines operate in non-laboratory environments (wet conditions)
transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would
have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of
an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are
usually 1.5 per unit or less.
Draft 5: December 17, 2010
27
FAC-003-2 — Transmission Vegetation Management
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is
considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1].
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 5: December 17, 2010
28
FAC-003-2 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
Table 5
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
8.89
5.65
3.52
3.35
1.6
IEEE 516
MAID (ft)
@ Alt. 3000 feet
8.65
4.92
3.13
2.8
1.4
Table 5
(historical maximums)
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.0
2.4
3.0
3.0
3.0
14.36
11.0
8.55
5.28
2.46
Draft 5: December 17, 2010
IEEE 516
MAID (ft)
@ Alt. 3000 feet
13.95
10.07
7.47
4.2
2.1
29
FAC-003-2 — Transmission Vegetation Management
Table 7
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
Draft 5: December 17, 2010
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
30
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Informal Comment Period Open
March 4 – April 4, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html.
Informal Comment Period Open through 8 p.m. Eastern on Monday, April 4, 2011
The Project 2010-07 Generator Requirements at the Transmission Interface drafting team has posted for a 30day informal comment period, a White Paper on proposed concepts to support the modifications of various
standards to clarify the reliability standard responsibilities of Generator Owners and Generator Operators at the
interface to the interconnected grid. The White Paper, along with proposed redlined changes to standards that
would be affected by the proposal, have been posted on the project Web page at
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html.
Instructions
The drafting team welcomes any constructive feedback for improving its proposal to ensure that the
responsibilities of Generator Owners and Generator Operators at the interface to the interconnected grid are
covered under NERC’s Reliability Standards. Consider using the following questions to focus your comments:
• How can the proposal outlined in the White Paper be improved? Is the drafting team heading in the
right direction?
• The drafting team has chosen to use informal means of receiving industry feedback (webinars,
presentations before industry stakeholder groups, etc.) prior to expending valuable industry resources to
develop specific proposals for reliability standard requirements, measures, VSLs, etc. Do you have any
further suggestions for seeking industry input before the project moves into a more formal development
phase?
• The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface” as part of this project. The Project 2010-07 drafting
team believes that changes to the definition of Bulk Electric System under Project 2010-17 and
modifications to a select group of standards can accomplish the same goal without the need for new
definitions. Do you support this approach? If not, please explain.
Please submit comments by e-mail to Mallory Huggins at mallory.huggins@nerc.net.
Next Steps
The drafting team will consider the input received on the concept White Paper as it continues its work.
Project Background
Significant industry concern exists regarding the application of Transmission Owner and Transmission Operator
requirements, and more specifically, the registration of Generator Owners and Generator Operators as
Transmission Owners and Transmission Operators based on the facilities that connect the generators to the
interconnected grid. NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in
2009 to analyze and make recommendations for establishing general criteria for determining whether Generator
Owners and Generator Operators should be registered for Transmission Owner and Transmission Operator
requirements in NERC’s Reliability Standards. The Ad Hoc Group developed a report evaluating the issues and
proposing a number of changes to add clarity on the requirements for generator interconnection facilities. Using
feedback from the industry, NERC, and FERC, the Project 2010-07 drafting team significantly revised the Ad
Hoc Group’s original proposal and offers a refined proposal here.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Summary
The drafting team welcomes any constructive feedback for improving its proposal to ensure that the
responsibilities of Generator Owners and Generator Operators at the interface to the interconnected
grid are covered under NERC’s Reliability Standards. Consider using the following questions to focus
your comments:
• How can the proposal outlined in the White Paper be improved? Is the drafting team heading in the
right direction?
• The drafting team has chosen to use informal means of receiving industry feedback (webinars,
presentations before industry stakeholder groups, etc.) prior to expending valuable industry
resources to develop specific proposals for reliability standard requirements, measures, VSLs, etc.
Do you have any further suggestions for seeking industry input before the project moves into a
more formal development phase?
• The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface” as part of this project. The Project 2010-07
drafting team believes that changes to the definition of Bulk Electric System under Project 2010-17
and modifications to a select group of standards can accomplish the same goal without the need for
new definitions. Do you support this approach? If not, please explain.
1
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Commenters
1. Connie Lowe, Dominion Resource Services………………………………………………………………………4
2.
Bob Folt, ReliabilityFirst Corporation……………………………………………………………………………….5
3. Doug Hohlbaugh, FirstEnergy Corp………………………………………………………………………………….6
4.
Laura Beane, Iberdrola Renewables………………………………………………………………………………..8
5.
Louis Slade, Dominion…………………………………………………………………………………………………….9
6.
Pat Hervochon, PSEG ......................................................................................................... 11
7.
Jay Seitz, U.S. Bureau of Reclamation................................................................................ 13
8.
Cynthia Janka, Arizona Public Service................................................................................ 15
9.
Sandy O’Connor, TransAlta ................................................................................................ 16
10. Denise Koehn, Bonneville Power Administration.............................................................. 17
11. Andy Pusztai, American Transmission Company............................................................... 18
12. John Troha, SERC OC Standards Review Group................................................................. 19
13. Jack Cashin, Electric Power Supply Assocation.................................................................. 21
14. Natalie Mazey, Texas Reliability Entity, Inc. ...................................................................... 27
15. Dan King, Sempra Generation............................................................................................ 29
16. Amir Hammad, Constellation Power Generation .............................................................. 32
17. Kurtis B. Chong, Independent Electricity System Operator............................................... 34
18. Sandra Shaffer, PacifiCorp ................................................................................................. 35
19. Annette M. Bannon, PPL Generation, LLC ......................................................................... 36
20. Natalie McIntire, American Wind Energy Association....................................................... 37
21. John Criner, Kelson Energy, Inc.......................................................................................... 39
22. Dale Fredrickson, Wisconsin Electric ................................................................................. 42
23. Ed Davis, Entergy Services ................................................................................................. 44
24. David Thorne, Pepco Holdings, Inc. ................................................................................... 45
25. Gretchen Schott, BP Wind Energy North America Inc....................................................... 46
26. Rebecca Baldwin, Transmission Access Policy Study Group.............................................. 49
27. Michelle D’Antuono, Occidental Energy Ventures Corp ................................................... 51
28. Greg Rowland, Duke Energy Corporation.......................................................................... 53
2
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
29. Kenneth A. Goldsmith, Alliant Energy................................................................................ 54
30. Lee Pedowicz, NPCC........................................................................................................... 55
31. John Bee, Exelon Corp........................................................................................................ 57
32. Patti Metro, National Rural Electric Cooperative Association........................................... 58
33. Ramiro Cerecer, Equipower Resources Corporation......................................................... 59
34. Eric Salsbury, Consumers Energy....................................................................................... 61
35. John DePoorter, Madison Gas and Electric Company ....................................................... 62
36. Carol Gerou, Midwest Reliability Organization ................................................................. 63
37. Louis C. Guidry, Cleco Support Group................................................................................ 65
38. Jonathan Hayes, Southwest Power Pool ........................................................................... 66
39. Cindy Martin, Southern Company ..................................................................................... 68
40. Thomas E. Goltz, American Electric Power........................................................................ 70
41. Kasia Mihalchuk, Manitoba Hydro..................................................................................... 72
42. Dan Roethemeyer, Dynegy ................................................................................................ 74
43. Dan Duff, Liberty Electric Power........................................................................................ 75
44. Gary Tarplee, Edison Mission Energy................................................................................. 76
45. John Hagen, Pacific Gas and Electric Company ................................................................. 77
46. Jonathan Appelbaum, The United Illuminating Company................................................. 78
47. Steve Alexanders, Central Lincoln ..................................................................................... 80
48. Larry Rodriguez, Entegra Power Services .......................................................................... 81
49. Greg Froehling, Green Country Energy.............................................................................. 82
50. Ken Parker, Entegra Power Group..................................................................................... 83
51. Mace Hunter, Lakeland Electric ......................................................................................... 84
3
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Connie Lowe, Dominion Resource Services
Connie.Lowe@dom.com
804-819-2917
COMMENTS:
Dominion agrees this is a good overall approach to identify specific TO/TOP requirements
associated with a qualifying generator and address an important registration and
potential reliability gap.
Minor suggestions include the following:
(1) The timeframe in R4 of 45 days could be increased to at least 90 days before a
GO is required to become compliant after it receives an interconnection request.
This additional time will allow proper coordination within other groups that
should stay in coordination.
(2) Need clarity in the white paper on page 3, 3rd paragraph that states “When the
transmission Elements and Facilities owned and operated by Generator Owners
and Generator Operators are non-network/non-integrated transmission, applying
all standards applicable to Transmission Owners and Transmission Operators
would have little effect on the overall reliability of the Bulk Electric System when
compared to the operation of the equipment that actually produces electricity –
the generation equipment itself.”
This statement seems to make sense when looked at from the GO/GOP perspective.
However what happens if the TO owns these transmission elements and facilities?
Would the TO be required to adhere to a smaller set of standards or all TO/TOP
standards for this subset of elements? This matter should be clarified.
Dominion has also answered the below questions posed by NERC below.
• How can the proposal outlined in the White Paper be improved?
Is the drafting team heading in the right direction? Yes
• The drafting team has chosen to use informal means of receiving industry feedback
(webinars, presentations before industry stakeholder groups, etc.) prior to expending
valuable industry resources to develop specific proposals for reliability standard
requirements, measures, VSLs, etc. Do you have any further suggestions for seeking industry
input before the project moves into a more formal development phase?
• The Ad Hoc group originally proposed the new terms “Generator Interconnection
Facility” and “Generator Interconnection Operational Interface” as part of this project. The
Project 2010-07 drafting team believes that changes to the definition of Bulk Electric System
Under Project 2010-17 and modifications to a select group of standards can accomplish the
same goal without the need for new definitions. Do you support this approach? YES
If not, please explain.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Bob Folt, ReliabilityFirst Corporation
Bob.Folt@rfirst.org
330.247.3087
COMMENTS:
Adobe Acrobat
Document
5
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Doug Hohlbaugh, FirstEnergy Corp.
hohlbaughdg@firstenergycorp.com
330-384-4698
COMMENTS:
Re: Project 2010‐07 Generator Requirements at the Transmission Interface
Informal Comment Period Ending April 4, 2011
Mallory Huggins
North American Electric Reliability Corporation
NERC Coordinator, Project 2010‐07 Generator Requirements at the Transmission Interface (“GOTO
Project”)
FirstEnergy (“FE”) appreciates the opportunity to provide comments on Project 2010 ‐07 Generator
Requirements at the Transmission Interface. FirstEnergy generally supports the Standard Drafting
Team’s (“SDT’s”) March 2011 “White Paper Proposal for Informal Comment” (“White Paper”) and its
recommended approach to scale back or eliminate many of the reliability standard revisions previously
proposed by the Ad Hoc team’s Final Report. The SDT’s White Paper largely aligns with prior comments
offered by FE on the GOTO Project. In comments filed in March 2010 in response to the Ad Hoc team’s
work and supported by FE, the ISO RTO Council Standards Review Committee stated as follows:
These SAR and associated draft standards changes go beyond what is needed to resolve the
GO/TO GOP/TOP registration issue. The only real changes that are needed are to include adding
GO and GOP applicability in the FAC‐003 standard so that vegetation management can be
enforced for lines built to interconnect generators without registering the GO/GOP as a TO/TOP.
All additional changes just add confusion and cause significant coordination issues with other
draft standard changes. This proposed SAR and associated standards’ modifications does not
appear to have been coordinated with any other drafting team. There are many standards and
requirements that are in various states of change. For instance, the TOP standards have been
significantly modified and are nearing the ballot phase. Coordination needs to occur before these
changes are balloted.
We applaud the drafting team for carefully considering comments submitted by our company and other
industry stakeholders.
FE Disagrees with the proposed FAC‐001 Changes:
As the White Paper acknowledges, Generator Owners (“GOs”) and Generator Operators (“GOPs”)
“should not be subject to the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Facilities and Elements that are part of the
integrated bulk power system.” Further, the White Paper properly states that subjecting GOs and GOPs
to all standards applicable to TOs and TOPs would do little to improve the reliability of the Bulk Electric
System (“BES”).
The proposed FAC‐001‐0 Requirement 4 would impose TO requirements on a GO simply because it
“receives an interconnection request for its (transmission) facility.” However, the White Paper is
premised on the assumption that GOs that receive interconnection requests are required to allow such
interconnection to go forward. The simple fact is that not every transmission facility that is owned by a
GO is subject to FERC’s “open access” requirements. FERC’s “open access” requirements apply only if
the line is used to provide FERC‐jursidictional transmission service. Many lines are not so used, and
therefore a decision to allow a third party to interconnect may lie entirely within the GO’s discretion.
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Generator Requirements at the Transmission Interface - Project 2010-07
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May 18, 2011
We offer the following suggested revisions to the proposed requirement R4 and the corresponding
measure M4:
R4. Generator Owner that is required to or elects to permit an interconnection request for its
facility shall make available to the requesting party its facility connection requirements addressing
items detailed in Requirement R2 above.
M4. The Generator Owner that is required to or elects to permit an interconnection request for its
facility shall make available (to its Compliance Monitor) for inspection evidence that it met the
requirements stated in Reliability Standard FAC‐001‐0 R4.
We appreciate NERC’s careful consideration of the comments provided. Should you have any questions
or require clarification please do not hesitate to contact me at 330 ‐384‐4698.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Laura Beane, Iberdrola Renewables
laura.beane@iberdrolaren.com
503- 478–6306
COMMENTS:
Iberdrola Renewables fully supports the recommendations in the “Project 2010-07: Generator
Requirements at the Transmission Interface White Paper Proposal”.
8
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Louis Slade, Dominion
louis.slade@dom.com
COMMENTS:
SERC OC Standards Review Group
Comments on Project 2010-07: Generator Requirements at the Transmission Interface
How can the proposal be improved?
1. Make the language clearer on the concept of a GO/GOP interconnection request to an
established GO/GOP that has an existing interconnection to the BES. It would be beneficial to
include a diagram(s) of interconnection examples.
2. We feel that the GO/GOP should not be forced into registration as a TO/TOP based on having a
radial connection (single point of connection) to the BES, provided that the loss of that radial
connection is included in the set of study contingencies by the TP and TOP.
3. The team should consider addressing exceptions to the typical (radial connection – single point
of connection) generator connections to the BES on a case-by-case basis involving the
appropriate parties, such as the GO/GOP/TO/TOP/TP and Regional Entity, rather than creating
requirements that apply to all GO/GOPs.
Is the drafting team headed in the right direction?
1. We applaud the team for seeking informal direction from the industry and believe the direction
that the team is taking is appropriate.
SERC OC standards Review Group Participation
Gerry Beckerle
Ameren
Jerry Hereen
MEAG
Jim Peterson
Santee Cooper
Shaun Anders
CWLP
Hamid Zakery
Dynegy
Scott McGough
OPC
David Plauck
Calpine
Pat McGovern
GTC
Melinda Montgomery Entergy
Shardra Scott
Gulf Power
Doug White
NCEMC
JakeMiller
Dynegy
Larry Rodriquez
Entegra Power
Jim Case
Entergy
Ray Phillips
AMEA
John Troha
SERC
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
“The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”
10
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Pat Hervochon, PSEG
Patricia.Hervochon@pseg.com
973 -430-5360
COMMENTS:
PSEG Registered Entities Comments on March 2011 White Paper on Generator
Requirements at the Transmission Interface
The PSEG Registered Entities (“REs”) support the work of the Ad Hoc Group for Generator
Requirements at the Transmission Interface subsequently placed under the aegis of the
Standard Development Team (“SDT”) for Project 2010-07. We appreciate this opportunity to
provide informal comments on the March 2011 White Paper on Generator Requirements at the
Transmission Interface (“White Paper”).
The PSEG REs support the concepts advocated in the White Paper, principally, that:
•
•
•
Subjecting Generator Owners (“GOs”) or Generation Operators (“GOPs”) to all of the
standards applicable to Transmission Owners (“TOs”) or Transmission Operators
(“TOPs”) would do little if anything to improve the reliability of the Bulk Electric System;
The goals of Project 2010-07 can be accomplished by making GOs and GOPs
responsible for complying with a limited number of reliability standard requirements,
namely certain requirements in FAC-001 and FAC-003; and
Creating new definitions for generator interconnection facilities and/or interfaces which
would be formalized in the NERC Glossary.
The PSEG REs also agree that ability to implement the concepts advocated in the White Paper
are inexorably linked to the work of the SDT assigned to Project 2010-17 (Definition of the Bulk
Electric System [“BES”]). We therefore recommend the two project teams coordinate their
efforts.
We are concerned by the suggestion that the requirements of FAC-001 are applicable within
forty-five days of receiving an interconnection request. There are a host of regulatory and
commercial activities and assessments that must be completed before the interconnection
occurs. In its role as the Regional Transmission Organization, PJM acts as the Transmission
Planner and coordinates and evaluates transmission interconnection requests. Furthermore,
experience shows that many of these interconnection requests are subsequently withdrawn
from the interconnection queues at PJM. Requiring GOs to be fully compliant with FAC-001
within 45 days of the receipt of such request for projects that may never be constructed would
not improve the reliability of the BES, but could result in an inefficient use of resources.
Therefore, we ask the SDT to consider alternatives to receipt of an interconnection request for
triggering FAC-001 applicability to GOs.
With regard to the requirement for GOs related to FAC-003, the PSEG REs support an
exemption for transmission facilities on the property of the GO. The SDT has acknowledged
this concept in paragraph 4.2.4 of FAC-003-02, but it is unclear exactly which facilities are
excluded by this exemption. Since PSEG believes that it is the intent of the SDT to include all
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
transmission lines on the generating station property as well as the some portion of the
transmission line that leaves the station property, we ask the SDT to adopt the approach
advocated by the Ad-Hoc Group. Under that approach, the vegetation management standards
in FAC-003-02 apply to GOs owning a Generator Interconnection Facility that operates at 200
kV and above, or are otherwise deemed critical to the BES, but provides for an exclusion from
FAC-003-02 for Generation Interconnection Facilities that reside within the GOs property line.
We also support an exemption for generator lead lines that leave the GO’s property but do not
exceed two spans (generally one-half mile from the generator property.
The PSEG Companies also acknowledge the efforts of the Electric Power Supply Association
(“EPSA”) to provide guidance and build consensus on this effort.
12
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Jay Seitz, U.S. Bureau of Reclamation
HSeitz@usbr.gov
303-445-2844
COMMENTS:
As stated, the purpose of Project 2010-07 is to clearly identify the appropriate generation
facilities and the standards requirements that should apply to such generation Facilities to
ensure that the reliability of the Bulk electric system is maintained. In pursuit of this purpose
judgment and discretion of the Registered Entities should be recognized.
The white paper proposes a role for Generator Owners well outside that of the existing NERC
Reliability Functional Model. BES facilities at which an entity may logically request
interconnection should be covered by a Transmission Owner and Transmission Operator. We
believe many of the concerns raised should be addressed by the registration process rather
than push Transmission Owner standards to the Generator Owner.
Specific comments to the white paper follow:
• How can the proposal outlined in the White Paper be improved? Is the drafting team heading in
the right direction?
The drafting team can improve its approach by limiting the applicability of those standards in
which the drafting team believes a reliability gap may exist for specific type of facilities. This will
help to ensure that interconnection requests or vegetation management is applied only to those
locations where network or integrated transmission exist.
The drafting team should spend more time on considering the comments provided to the ad hoc
team when it developed its final report. Specifically, as stated in the SAR, the drafting team
needs to “add particular focus on the operation of the interface point at which operating
responsibility shifts from the Generator Operator to the Transmission Operator.” The drafting
team appears to have sidestepped the action by what appears to be unilaterally dismissing the
work of the ad hoc Team.
The drafting team proposal is not adequately addressing the interface issue in its proposal. The
drafting team did recognize that while elements owned by entities who are registered as
Generator Owner appear to fit the definition of elements owned by Transmission Owners, the
elements need not be subject to the same level of standards applicable to Transmission Owners.
The drafting team also recognized that those elements are generally non network or non
integrated transmission elements. Simply put they are not used to transmit power other than
from the specific Generator Owner. The proposal submitted for comment does not recognize the
non network/non integrated transmission nature of the elements when it proposes to apply FAC001 to Generator Owners. The purpose of FAC-001 is for facilities where network or integrated
transmission exists. By applying FAC-001, the Generator Owner “transmission’ type elements,
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
would be de facto considered network transmission and would then require the Generator
Owner to develop interconnection requirements at Generator facilities. Since the Generator
Owner now would have a recognized network facility, it would also be subject to FERC Order 888
and be required to develop rates for the use of its facilities.
Finally, the drafting team recognized that the definition of BES would drag certain GO into a TO
arena with little if any improvement in reliability of the Bulk Electric System. The drafting team
should recognize that if the Generator Owners are in fact required to register as Transmission
Owners, the proposed changes to the standards would open the Generator Owner to
interconnection requests at other than transmission system voltage levels.
• The drafting team has chosen to use informal means of receiving industry feedback (webinars,
presentations before industry stakeholder groups, etc.) prior to expending valuable industry
resources to develop specific proposals for reliability standard requirements, measures, VSLs, etc.
Do you have any further suggestions for seeking industry input before the project moves into a
more formal development phase?
The drafting team should build upon the work of the ad hoc Team which encompasses much of
the industry feedback on the subject. The suggestion to modify FAC -001 and FAC-003 do not get
to the root of the concerns and do not address the interface issue addressed raised by industry.
• The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface” as part of this project. The Project 2010-07
drafting team believes that changes to the definition of Bulk Electric System under Project 201017 and modifications to a select group of standards can accomplish the same goal without the
need for new definitions. Do you support this approach? If not, please explain.
This action is not supported. The industry spent a great deal of time responding to the white
paper drafts which resulted in the recommendation for the new terms. Without defining the
interface issues and where they exist, modification of the standards cannot hope to deal with the
true reliability issue.
14
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Cynthia Janka, Arizona Public Service
Cynthia.Janka@aps.com
602-250-2028
COMMENTS:
Chris Cambridge, Engineering Manager and GO GOP Subject Matter Expert submits
the following comments on behalf of Arizona Public Service (AZPS).
The Standards Drafting Team (SDT) for this project is trying to address the Reliability
Standards required for a Generator Owner and Operator who has interconnection facilities
(referred to as a GOTO). The SDT has provided various approaches for industry comment
and AZPS is providing comments on the following two approaches:
Requiring any classification that subjects Generator Owners and Generator Operators to all
the standards applicable to Transmission Owners and Transmission Operators would do
little, if
anything, to improve the reliability of the Bulk Electric System (see page 3).
To maintain an adequate level of reliability in the Bulk Electric System, a clear delineation of
responsibilities and authority at the interface between Generator Owners/Operators and
Transmission Owners/Operators is needed. This can be accomplished by properly applying
selected standards or specific standard requirements to Generator Owners and Generator
Operators (see page 3).
Taking this approach the SDT has done an admirable job of trying to address requirements
for this special group of Generator Owners and Operators with generator interconnection
facilities without requiring them to comply with all the Transmission Owner and Operator
Reliability Standards. However, it does not appear that they have looked at the impact of
adding the Generator Owner and Operator to select reliability standards applicable to
Transmission Owner and Operator and how this will add additional compliance requirements
to the rest of Generator Owners and Operators in the industry. It may be more appropriate
to consider the creation of another entity as a Generator Interconnect to clarify
the distinction from having full TO/TOP responsibilities. Then the specific requirements could
be distinguished between the TO/TOP and GO/GOP.
The SDT has also made the following statements which although understandable do not
provide the confidence this is the correct approach in extending the requirements of a
Generator Owner and Operator into certain Transmission Owner and Operator standards.
The second statement below, as indicated, will considerably alter the SDT previous direction
and may limit this approach.
The SDT recognizes that its work alone may not eliminate all reliability gaps with respect to
generator-owned Facilities like generator interconnection facilities (see page 7).
As noted above, Project 2010-17—Definition of Bulk Electric System may have an enormous
impact on the work of this SDT. We are confident that these changes we have proposed to a
small number of standards, in coordination with changes to the Bulk Electric System
definition, can achieve the necessary reliability (see page 7).
AZPS's ultimate recommendation is to consider adding a new entity to address the specific
standards and requirements needed by a Generator Interconnect Facility versus adding
additional requirements for a Generator Owner and Operator which are applicable to the
Transmission Owner and Operator.
15
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Sandy O'Connor, TransAlta
sandy_o'connor@transalta.com
403-267-7638
COMMENTS:
TransAlta Centralia Generation LLC (TransAlta) appreciates the opportunity to provide
comments on Project 2010-07 Generator Requirements at the Transmission Interface
White Paper Proposal for Informal Comment.
TransAlta strongly encourages the continued progress on Project 2010-07. Completion of
this project is important to bring resolution to the industry regarding not only the "go
forward approach" but also for those generators that have already been registered as
Transmission Owners and Transmission Operators.
TransAlta offers the following specific comments:
1. Overall TransAlta agrees with this more simplified approach. The white paper
proposal describes the analysis undertaken by the Standard Drafting Team (STD)to
arrive at the shorter list of standard which would require SARs - FAC-001 and
FAC-003. We believe this approach is appropriate and logically puts some of the
larger issues into forums that are already addressing those issues.
2. One of the recommendations in the white paper proposal is to follow Project 201017 Definition of Bulk Electric System and ensure that the responsibility for
generator interconnection line leads is appropriately and clearly assigned to
Generator Owners and Operators. TransAlta recognizes that Project 2010-017 is
likely the more appropriate forum to deal with the definition of Bulk Electric
System and the associated impact on the definition of generator interconnection
line leads. TransAlta would recommend not only following Project 2010-07, but
also active involvement in the project by the SDT to ensure that the responsibility
for generator line leads is properly assigned.
3. Under the Section "Summary and Discussion of Other Options" the white paper
proposal outlines a number of different options that are available to an entity to
manage compliance responsibility. While TransAlta agrees that these options are
available, what is important to note is that in many cases these options are
difficult, costly and time consuming to implement, resulting in compliance risk for
those generators that are registered by a regional entity and NERC for the
Transmission Owner and Transmission Operator functions. The compliance risk
placed on a generator after registration is one of the reasons we encourage the
continued progress on Project 2010-07.
Thank you for considering our comments.
16
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Denise Koehn, Bonneville Power Administration
dekoehn@bpa.gov
360-418-2533
COMMENTS:
Bonneville Power suggests that the following phrase be included:
“the GO shall coordinate with the TO to ensure that all interconnection facilities are
included in the vegetation management plan”. This phrasing would leave it up to
the GO and TO to determine how to coordinate most effectively.
We appreciate your consideration of our comment.
17
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Andy Pusztai, American Transmission Company
apusztai@atcllc.com
(262) 506-6913
COMMENTS:
American Transmission Company LLC (ATC) wishes to thank NERC for providing an opportunity to
comment on the NERC Project 2010-07 “Generator Requirements at the Transmission Interface”
White Paper as requested in the NERC posting dated March 4, 2011.
ATC reviewed the subject White paper using the recommended focus questions in the NERC
posting and has a couple comments. They are summarized in the attached document.
Thanks again for providing an opportunity to comment.
1. How can the proposal outlined in the White Paper be improved? Is the drafting team
heading in the right direction?
Improvements:
Next Step #1 - According to FERC Docket #ER10-1117, if a Generator Owner receives a request for
service over their facilities; they have 60 days to file a tariff for processing the request for service. ATC
believes that the proposed Requirement R4 of FAC-001 should give the Generator Owner 60 days, rather
than 45 days, to provide its interconnection requirements.
Next Step #3 – NERC has not clearly defined wind farms to be generating plants. The words, “directly
connected via a step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or
above”, in the latest Project 2010-17 concept paper may not be interpreted as applicable to wind farms.
The generating units of wind farms are typically directly connected to sub-transmission facilities, which
in turn are directly connected to Transmission Facilities operated at voltages of 100 kV or above.
ATC agrees the drafting team is heading in the right direction.
2. The drafting team has chosen to use informal means of receiving industry feedback
(webinars, presentations before industry stakeholder groups, etc.) prior to expending
valuable industry resources to develop specific proposals for reliability standard
requirements, measures, VSLs, etc. Do you have any further suggestions for seeking
industry input before the project moves into a more formal development phase?
No
3. The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility”
and “Generator Interconnection Operational Interface” as part of this project. The Project
2010-07 drafting team believes that changes to the definition of Bulk Electric System under
Project 2010-17 and modifications to a select group of standards can accomplish the same
goal without the need for new definitions. Do you support this approach? If not, please
explain.
Yes, ATC supports the approach.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
John Troha, SERC OC Standards Review Group
jtroha@serc1.org
COMMENTS:
SERC OC Standards Review Group
Comments on Project 2010-07: Generator Requirements at the Transmission Interface
How can the proposal be improved?
4. Make the language clearer on the concept of a GO/GOP interconnection request to an
established GO/GOP that has an existing interconnection to the BES. It would be beneficial to
include a diagram(s) of interconnection examples.
5. We feel that the GO/GOP should not be forced into registration as a TO/TOP based on having a
radial connection (single point of connection) to the BES, provided that the loss of that radial
connection is included in the set of study contingencies by the TP and TOP.
6. The team should consider addressing exceptions to the typical (radial connection – single point
of connection) generator connections to the BES on a case-by-case basis involving the
appropriate parties, such as the GO/GOP/TO/TOP/TP and Regional Entity, rather than creating
requirements that apply to all GO/GOPs.
Is the drafting team headed in the right direction?
2. We applaud the team for seeking informal direction from the industry and believe the direction
that the team is taking is appropriate.
SERC OC standards Review Group Participation
Gerry Beckerle
Ameren
Jerry Hereen
MEAG
Jim Peterson
Santee Cooper
Shaun Anders
CWLP
Hamid Zakery
Dynegy
Scott McGough
OPC
David Plauck
Calpine
Pat McGovern
GTC
Melinda Montgomery Entergy
Shardra Scott
Gulf Power
Doug White
NCEMC
JakeMiller
Dynegy
Larry Rodriquez
Entegra Power
Jim Case
Entergy
Ray Phillips
AMEA
John Troha
SERC
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
“The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”
20
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Jack Cashin, Electric Power Supply Association
jcashin@epsa.org
(202) 349-0155
COMMENTS:
EPSA Comments on Generation Requirements at the Transmission Interface – Project
2010-07
The Electric Power Supply Association (EPSA) 1 endorsed the initial recommendations of the Ad
Hoc Group for Generator Requirements at the Transmission Interface, and appreciates the
opportunity to offer these informal comments on the March 2011 White Paper Proposal for
Project 2010-07. Since NERC’s creation of the “GOTO Team” in February of 2009, EPSA has
supported the efforts of Ad-Hoc Group and now the Project 2010-07 Standards Drafting Team
(SDT). While EPSA members’ compliance registration includes several functional entity types,
the bulk of competitive suppliers’ registrations are as Generator Owners (GOs) and Generator
Operators (GOPs).
EPSA’s comments herein will focus on the following points for the Project 2010-07 SDT to
consider concerning the White Paper Proposal:
•
•
•
•
The definitions included in the currently underway Bulk Electric System (BES) definition
Standard drafting effort and Generator Requirements at the Transmission Interface
need to be aware of each SDT’s work. Thus, the Project 2010-07 SDT should regularly
consult with the Project 2010-17 SDT so that the two projects work as coordinated
efforts.
So that the Interface between generation and transmission can be clearly demarcated,
correctly defining generator interconnection facilities is crucial to the successful
completion of Project 2010-07.
EPSA largely supports the White Paper’s correct assessment about how Project 201007 will either require slight or no modification of other Standards to maintain reliability.
Competitive Suppliers agree that FAC-001-1 and FAC-003-2 should apply to GOs, but
suggest that the SDT revisit and revise the criteria that would trigger compliance for
these two Standards.
BES Definition and Exemptions – Working with Project 2010-17
1
EPSA is the national trade association representing competitive power suppliers, including generators and marketers. These
suppliers, who account for 40 percent of the installed generating capacity in the United States, provide reliable and competitively
priced electricity from environmentally responsible facilities serving power markets. Each EPSA member typically operates in four or
more NERC regions, and members represent over 700 registered entities in the NERC registry. EPSA seeks to bring the benefits of
competition to all power customers. The comments contained in this filing represent the position of EPSA as an organization, but
not necessarily the views of any particular member with respect to any issue.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Importantly, Project 2010-07 seeks to work in a coordinated way with the Definition of Bulk
Electric System (BES) and Related Rules of Procedure Development Team – Project 2010-17
to appropriately designate facilities that would be included as part of the BES. The BES
definition standard and associated exemption criteria need to be clear and widely understood so
that BES generation and transmission facilities know their reliability responsibilities. The Project
2010-17 SDT needs to develop a crisp BES definition that can meld with the exemption criteria
that will be developed. Importantly, the White Paper in stating Project 2010-07 Purpose, notes
the Project’s intent to have all generator BES facilities identified and integrated with other NERC
Standards to ensure reliability. From the Paper:
The purpose of Project 2010-07—Generator Requirements at the Transmission
Interface is to ensure that all generator-owned Facilities that are considered part
of the Bulk Electric System are identified and that the level of reliability needed to
operate such Facilities is appropriately covered under NERC’s Reliability
Standards. 2
While the two efforts need to move forward in a coordinated way, neither project should impede
the other’s efforts or be stalled by the other’s timetable.
EPSA supports the SDT’s Purpose because it will eliminate the current conundrum when GO &
GOPs are registered as TO & TOPs. This creates an untenable situation where GO & GOPs
must comply with TO & TOP applicable standards despite not participating in the drafting of
those Standards, because there was no evidence at the time that they would ever be registered
as TO & TOPs. Project 2010-07 begins the process to change this situation and ensure
against potential BES reliability gaps. By identifying the Standards that are appropriate for
specific GO & GOPs the White Paper sets the course for the ERO to properly give GO & GOPs
the due process accorded them under Section 215 of the Federal Power Act (FPA). Hence,
generators can be engaged in the Project 2010-07 process so that those GO & GOPs that need
additional responsibilities typically applicable to TO & TOPs will understand their full compliance
obligations and ensure BES reliability. Moreover, coordination among Project 2010-07 and
Project 2010-17 will ensure that the Standards will eliminate potential BES reliability gaps.
The Need for a Generator Interconnection Facilities Definition
EPSA supports the SDT assertion that generating elements and facilities should be classified as
part of the BES. Moreover, a clear BES definition will only be successful if the point of
interconnection and associated functional registration is properly defined. The White Paper
notes the need for good definitions for appropriate classification:
While not all power plants are considered part of the Bulk Electric System,
ultimately, all the plants are interconnected to the bulk power system via their
generator interconnection facilities. Of concern is how to classify all such
2
Project 2010-07: Generator Requirements at the Transmission Interface, White Paper Proposal for
Informal Comment, March 2011, Page 2.
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generating facilities, including their generator interconnection facilities, to
determine what level of reliability is needed for such facilities. 3
Generally, EPSA agrees with the SDT’s conclusion that, “new definitions, modifying other
definitions, and making changes to dozens of standards was no longer necessary.” Much as
the White Paper discusses (and is addressed later in these comments) many of the changes
occurring through the BES revision will obviate the need for some of the definitional and
standard modifications anticipated by the Ad-Hoc Group in 2009. EPSA agrees with this White
Paper conclusion with the exception of generator interconnection facilities. A definition for
generation interconnection facilities is necessary in Project 2010-07 Standard so that the
interface between generators and transmission system can be clearly established and any
ambiguities about reliability responsibilities for GOs & GOPs and TO & TOPs are eliminated.
The Ad-Hoc Group Report recommended the following definitions for incorporation into the
existing standard:
Generator Interconnection Facility
Sole-use facility for the purpose of connecting the generating unit(s) to the transmission grid. In
this regard, the sole-use facility only transmits power associated with the interconnecting
generator, whether delivered to the grid or delivered to the generator for station service or
auxiliary load, or delivered to meet cogeneration load requirements.
Generator Interconnection Operational Interface
Location at which operating responsibility for the Generator Interconnection Facility changes
between the Transmission Operator and the Generator Operator. 4
These definitions were developed with due consideration for varying configurations, outages,
and generators materiality to the BES. The Facility definition defines the purpose of the facility,
while the Generator Interconnection Operational Interface definition provides the functional lines
of demarcation between the GO and the TO. The definitions were developed based on the
purpose of generator interconnection facilities, their usage and how their usage differs from
transmission facilities that comprise the interconnected grid. EPSA believes this is a sound
basis for distinguishing BES facilities.
EPSA encourages the Project 2010-07 SDT to consider fitting the above definitions into the
current White Paper for inclusion in the NERC Glossary. In addition, the other definitional
changes proposed in the Ad-Hoc Group Report 5 should be retained and be considered for
Glossary modification.
3
Id at Page 1.
Generator Requirements at the Transmission Interface Final Report – Ad Hoc Group, November 16,
2009, Pages 17-18.
5
Id at Pages 16-17.
4
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Provided that there have been several FERC appeals 6 associated with this issue, EPSA
encourages the SDT to include the above definitions so that registration can be based on a
sound definition for generator interconnection facilities on which complying entities can rely. By
providing the above definitions and changes to the NERC Glossary will add needed clarity.
Including a generator interconnection facility definition in the Standard and in turn the NERC
Glossary will appropriately set the stage for compliance registry criteria changes. EPSA
believes the Project 2010-07 SDT should provide the definition changes for compliance registry
amendment at the earliest date available so that any perceived registration reliability gaps can
be corrected. Subsequently, as Regional Entities are considering new registrations they will
have stronger criterion on which to base their decisions, which will make it so that NERC can
“measure twice and cut once,” avoiding unnecessary resources expenditure on appeals.
Project 2010-07 and Other Relevant Reliability Standards
EPSA generally supports proposed next steps and recommendations provided in the White
Paper. This section of the paper updates (since the Ad-Hoc Group Report) the review of
Standards and their requirements that should apply to appropriate generation facilities.
Competitive suppliers agree with the SDT’s conclusions that the Standards list beginning on
page 5 of the White Paper 7 already apply to GO & GOPs due to changes since the Ad-Hoc
Group Report and therefore do not need to be addressed further in Project 2010-07. The
further White Paper discussion about how the circumstances for the EOP and PER and TOP
(including considerations of PRC-001-2) Standards on pages 6 and 7 provides sound reasons
that make EPSA believe that any reliability gaps perceived in 2009 that have since been closed.
Actions that Trigger Applicability of the FAC Standards
The first recommendation in the White Paper is to include GOs in the applicability section of
FAC-001-0, an assertion with which EPSA agrees. Appropriate generation facilities that would
be identified as needing to comply with FAC-001-0 would need to comply with the Standard to
ensure the reliability of the BES. However, EPSA is concerned with the White Paper’s proposal
that Requirement 4 be added to the applicability section of FAC-001-1. The proposed
Requirement reads:
R4. Generator Owner that receives an interconnection request for its facility shall,
within 45 days of such request, be required to comply with requirements R1, R2,
R3 for the facility for which it received the interconnection request.
EPSA cautions the SDT about inadvertently commingling commercial issues with reliability
issues. The interconnection requests involve other tariff issues for both GOs and TOs that need
to be resolved before compliance can be established. Reliability will not be degraded if the
triggering event for Standard compliance is set after the completion of other commercially
6
New Harquahala Generating Company, LLC, 123 FERC 61,173 (“New Harquahala”), order on
clarification, 123 FERC 61,311 (2008); Cedar Creek Wind Energy, LLC, RC11- 1-000, appeal, 2010;
Milford Wind Corridor Phase I, LLC, RC11-2-000.
7
Project 2010-07: Generator Requirements at the Transmission Interface, White Paper Proposal for
Informal Comment, March 2011, Page 5.
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related regulatory obligations. Examples of commercial obligations that would need to be
resolved include the need for an Open Access Transmission Tariff (OATT) to be filed with
respect to the interconnection. During the proposed 45 day and potentially beyond, issues
regarding transmission upgrades and financial responsibility for those upgrades would need to
be resolved. Until upgrade issues are resolved, facility ownership and operation and
maintenance responsibilities will not be specifically known. Additionally, if transmission owner
and the interconnecting generator are affiliates, waivers with FERC acceptance will be required.
The OATT and associated upgrade and affiliate waiver issues would need time to be sorted out
prior to a registered GO being required to meet the requirements of FAC-001-0. Consequently
triggering reliability compliance 45 days after the interconnection request is not feasible and
does not enhance BES reliability. EPSA believes the SDT should ensure that reliability
compliance should not be required before OATT changes and potential waivers are completed.
Hence the criteria for triggering GO compliance with FAC-001-0 should only come into play after
all commericial OATT issues are resolved.
The White Paper also proposes that the Generator Owner be added to all the requirements and
measures that mention Transmission Owner for FAC-003-2. FAC-003-2 should apply to
appropriate GOs, however EPSA asserts that the current proposal, which suggests applying the
Standard to all generator interconnection facilities needs to have a more specific criteria to
distinguish the specific GOs that need to comply with FAC-003-2. This would be consistent with
the approach that was used by the Ad-Hoc Group in its Report where the “two-span test was
supported for determining which GOs that FAC-003 should apply to:
In reaching this conclusion, the team considered other options that included
inclusion of Generator Owners as applicable entities to FAC-003 based on a test
for criticality, or to include Generator Owners as applicable entities in the existing
version of FAC-003 without modification to the applicability criteria. The team,
supported by a majority of industry commentors [sic] indicated the two-span test
presented a simple and objective method to determine responsibilities for
Generator Owners. Additionally, the “200 kV and above, or otherwise deemed
critical to the Bulk Electric System” threshold is consistent with the current
applicability of FAC-003 to Transmission Owners. 8
EPSA supports the approach endorsed during the development of the Ad-Hoc Group Report
and believes that FAC-003-2 need only apply to GOs with significant voltages and distances.
Only Generator Owners of a Generator Interconnection Facility whose facilities operate at 200
kV and above or are otherwise deemed critical to the BES and whose Generation
Interconnection Facility exceeds two spans (generally one-half mile from the generator property
line) should need to comply with the vegetation management Standard. Therefore, the SDT
should reexamine if FAC-003-2 should apply to all GOs only based on the generator
interconnection facility. This must be done in conjunction with revising the definition of
generator interconnection facilities.
8
Generator Requirements at the Transmission Interface Final Report – Ad Hoc Group, November 16,
2009, Pages 15.
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Conclusion
In summary, EPSA endorses SDT’s work and appreciates the posting of the White Paper for an
informal comment period. The White Paper provides an important bridge for Stakeholders to
weigh current recommendations with the 2009 Ad-Hoc Group Report. Generally, EPSA agrees
with the SDT’s recommendations but still feels that to ensure that there are no BES reliability
gaps requires coordination with the current BES SDT Project 2010-17; a definition for generator
interconnection facilities needs to be included in the Standard; the Standards that no longer
require changes since the 2009 Ad-Hoc Report have been correctly assessed; and, the
compliance triggers and criteria for the FAC Standards need to be revised. Therefore, EPSA
respectfully requests that the SDT for Project 2010-07 consider the recommendations herein.
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Natalie Mazey, Texas Reliability Entity, Inc.
natalie.mazey@texasre.org
512-583-4928
COMMENTS:
Comments of the ERCOT Region NERC Standards Review Subcommittee (NSRS) on NERC Project 201007 White Paper Proposal on Generation Requirements at the Transmission Interface (GRTI)
Submitted by: Group – ERCOT Region NERC Standards Review Subcommittee
Participating Members:
Name
Organization
Region
Bruce Wertz (Chair)
Independent Consultant
ERCOT
Pamela Zdenek (Vice Chair)
BP Products North America, Inc.
ERCOT
Brenda Hampton
Luminant
ERCOT
Tim Soles
Independent Consultant
ERCOT
Tom Foreman
LCRA
ERCOT
Contact: Natalie Mazey, Standards Development Coordinator, Texas Reliability Entity, Inc.
1. Coordination between Standard Drafting Teams. Based on the current status of the Bulk Electric
System Standard Drafting Team (BESSDT) proposed BES definition, the White Paper Proposal
(“Proposal”) does not provide a clear demarcation between generator interconnection facilities and
the interconnected transmission facilities of the Transmission Owner/Operator.
The current BES definition makes no mention of what are or are not considered generation
interconnection facilities, but merely includes “generating units greater than 20 MVA (aggregated 75
MVA at one site) from the generator terminals through the GSU which has a high side voltage of 100
KV or above.” Many registered generators own an additional interconnection line that is above 100
KV that, in turn, connects the generator to the transmission owner’s facilities and is also part of the
generator interconnection. The currently proposed BES “core definition” would classify this line as a
Transmission Element and could conceivably subject the GO to the full array of TO/TOP standards
for this interconnection line.
According to its scope, the BESSDT is looking to the GRTISDT to define this demarcation through a
definition, as proposed by the Ad Hoc group. As we interpret its scope, the BESSDT is defining what
is or is not part of the BES without specifying what standards apply to different parts of the BES, or,
for that matter, what standards apply to non-BES facilities.
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The NSRS asks for clarity of the definition, “generation interconnection facility” and for that
definition to be included in the NERC Glossary. This subcommittee has no preference as to which
committee takes ownership of this definition; however, we are substantially interested in
expediting the completion of the review of this definition.
2. Generation Interconnection Lines. The NSRS disagrees that generation interconnection lines are
transmission lines from a functional standpoint. The function of the interconnection line is to
interconnect the generator with the transmission system in a similar manner to the connectivity of a
local distribution system to the transmission system (i.e., generally radial in nature). These lines only
carry the output power or auxiliary power for that generation unit and are not for public use.
The transmission system function is to deliver the generation to the load. That is not to say that
some standards related to higher voltage lines may apply. Merely that, from a functional
standpoint, the two are not the same and the reliability requirements are not the same.
The NSRS agrees with the approach the SDT is taking involving the addition of a GO function to
FAC-003. In the ERCOT Protocols, the definition of “Power Generation Company” (“PGC”) states
that the PGC does not own a transmission or distribution Facility in this state other than an
essential interconnecting Facility…” Therefore, by definition, a PGC cannot be TO/TOP.
3. Proposed FAC-001 Revisions. The proposed FAC-001 revisions should not apply in the ERCOT region.
In the ERCOT region, generation interconnection lines are private facilities that are not subject to
third party interconnection requests. This revision only applies to a generation interconnection line
that is considered part of the transmission network and for which the GO receives compensation for
making this transmission line available.
The FAC-001 revisions should include a regional difference exempting Generation Owners in the
ERCOT region.
4. Proposed FAC-003 Revisions. The NSRS agrees with the Ad Hoc Group’s Proposal 2, which provides
for exclusions for short distance interconnections (i.e. - interconnection lines that do not exceed a
distance that can be reasonably monitored), from the generator property line. In addition, there
should be a process for demonstrating to the Regional Entity that the interconnection line has no
vegetation around it to manage, i.e. in arid locations. Each entity should be allowed to develop this
process based on their circumstances at their facility.
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Dan King, Sempra Generation
daking@SempraGeneration.com
(619) 696-4350
COMMENTS:
Comments of Sempra Generation on the Project 2010‐07 Generator
Requirements at the Transmission Interface White Paper
Sempra Generation is the parent company of several generation‐owning subsidiaries in
the Western Electricity Coordinating Council region, including Mesquite Power, LLC (Mesquite),
which is currently registered as both a Generator Owner/Generator Operator (GO/GOP) as well
as a Transmission Owner/Transmission Operator (TO/TOP) due to the ownership of generator
interconnection facilities.
Sempra Generation commends the work of the Project 2010 ‐07 Standards Drafting
Team (SDT) and believes the team is heading in the right direction, as evidenced by the March
2011 White Paper currently open for comment. Sempra Generation supports the position of
the SDT that generator interconnection facilities should not trigger registration as a TO or TOP
simply because the GO owns and/or operates transmission elements or facilities. Having said
that, Sempra Generation agrees that, in order to maintain an adequate level of reliability in the
Bulk Electric System, selected standards and requirements should apply to GO/GOPs in order to
establish and maintain a clear delineation of responsibilities with respect to their generator
interconnection facilities.
In the brief comments below, Sempra Generation provides feedback to the SDT on
specific proposals in the White Paper.
• Applicability of FAC‐001‐0 to the Generator Owner
The SDT’s proposed approach to FAC‐001‐0, which would require a GO to fully
implement the R1 – R3 requirements within 45 days in the event the GO receives an
interconnection request, may pose some difficult practical hurdles for GOs. A third‐party
request to interconnect to the GO’s facilities would most likely occur in the circumstance where
an existing radial transmission facility is sufficiently sized to accommodate additional
generation, as is sometimes the case for renewable generation in particular, given that these
facilities are also often sited many miles from the grid.
Third‐party interconnection requests notwithstanding, if a GO is not also registered as a
TO/TOP, it is because, as recognized at p. 3 of the White Paper, that GO’s interconnection
facilities are radial in nature, rather than “integrated.” Adding an interconnecting third ‐party
generator user to the GO’s radial gen‐tie facility does not automatically make that facility an
“integrated” transmission element. If the GO’s transmission facilities are not “integrated,” it is
generally going to be infeasible for the GO to fully implement the R1 ‐ R3 requirements, since
those requirements are clearly designed for owner/operators of integrated transmission
facilities. In all actuality, the most appropriate entity to coordinate the process from the
technical standpoint of facility connection requirements would be the BAA/TSP to whom the
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GO is interconnected, since the BAA/TSP would invariably be an “Affected System” under the
FERC’s pro forma Large Generator Interconnection Procedures.
Some of the practical difficulties facing GOs were recently highlighted by participants
and panelists at the FERC Technical Conference on participant ‐funded transmission (Docket No.
AD11‐11‐000, et al., March 15, 2011), where FERC is considering how to better implement the
OATT requirement for participant‐funded transmission facilities (including gen‐tie facilities). In
light of the discussion at the Technical Conference, it is reasonable to assume that FERC may be
making adjustments to its policies in the future regarding how to address third ‐party access to
GO interconnection facilities.
In addition, the seeming impracticality of a generator complying with FAC ‐001‐0 R1‐R3
was acknowledged and documented in 2008 by NERC and WECC in the Harquahala
“Compliance Protocol” document, which was recently filed at FERC in the Cedar Creek
Wind/Milford Wind Corridor proceeding (FERC Docket No. RC11‐1‐000 et al., filed December
28, 2010). With respect to compliance with FAC‐001‐0 R1‐R3, the Compliance Protocol
provides as follows:
Because Harquahala does not know what equipment would be required for a specific
interconnection to the Harquahala transmission facilities, to satisfy these Requirements,
Harquahala will generally describe the factors it will consider if interconnection is
requested, including ay necessary coordination with SRP, and the necessity of installing
certain equipment for measuring interconnection capability. Harquahala will not be
required to publicly publish its facility connection requirements, but Harquahala will
provide them upon request, as required in R3. If Harquahala were to receive a request for
interconnection, Harquahala will work with the requesting entity to develop full
interconnection requirements in a timely manner.
Instead of requiring the GO to comply with the full panoply of FAC ‐001‐0 R1 – R3
requirements (all within 45 days of the third ‐party interconnection request), Sempra
Generation encourages the SDT to consider R4 language that recognizes the practical hurdles
associated with implementing the requirements for radial facilities, and that takes an approach
more akin to the Harquahala Compliance Protocol with respect to this Standard. Specifically,
the SDT should consider R4 language that would require the GO receiving the interconnection
request (i) to implement the requirements of R1 – R3 only to the extent those requirements are
applicable to radial facilities; and (ii) to coordinate with its BAA/TSP on such implementation. In
terms of timing, the SDT should consider whether the proposed 45 days is realistic, and
whether a 90‐day deadline would be more appropriate. The flexibility inherent in the above
approach would likely avoid potential conflicts with any revised FERC policies resulting from the
aforementioned Technical Conference.
• Applicability of FAC‐003‐2 to the Generator Owner
Sempra Generation supports the addition of “Generator Owner” to the Applicability
section of FAC‐003‐2.
•
Project 2010‐17—Definition of Bulk Electric System
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Sempra Generation supports the need for the coordination between the Project Teams
for Project 2010‐07 and Project 2010‐17 (Definition of Bulk Electric System), and agrees that
changes made to the BES definition will be instrumental in covering the reliability gap with
respect to generator requirements at the transmission interface. However, because the Project
2010‐17 BES work may take a significantly slower track than the SDT’s progress, Sempra
Generation encourages the SDT to weigh the risks and benefits of including of a definition of
“Generator Interconnection Facility” in the NERC Glossary and associated clarifications to the
standards, as proposed in the Final Report from the Ad Hoc Group for Generator
Requirements at the Transmission Interface.
• Other Solutions
As referenced in the White Paper, the standards outlined will likely not take effect for a
year or more. In the meantime, GOs such as Mesquite will continue to be under increased risk
of non‐compliance due to their registration as TO/TOPs, and will need to incur substantial
compliance costs for TO/TOP requirements that are clearly not an appropriate fit. Accordingly,
Sempra Generation encourages consistent application of responsibilities under the Standards in
all NERC regions, and urges NERC to adopt the necessary changes to the NERC Glossary,
Registration Criteria, and/or Standards to ensure consistency exists throughout the regions.
• Conclusion
The Final Report and White Paper are obviously products of detailed analysis and
thoughtful consideration of the myriad issues surrounding the reliability implications of
ownership and operation of generator interconnection facilities. It is noteworthy – though
hardly surprising – that, after many months of study, the GO/TO Task Force and the SDT,
balanced groups comprised of members from a broad spectrum of functional categories, have
concluded that only modest changes to the Reliability Standards would be required in order to
ensure that no gaps exist and that generator interconnection facilities are operated reliably.
When implemented, the recommendations included in the White Paper should go a
long way toward providing the regulatory and compliance certainty needed by generators who
own or operate generator Interconnection facilities. Accordingly, Sempra Generation
encourages the continued work of the Project 2010 ‐07 team.
Sempra Generation is not the same company as the utility, SDG&E or SoCalGas, and the California Public Utilities
Commission does not regulate the terms of Sempra Generation’s products and services.
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Amir Hammad, Constellation Power Generation
Amir.Hammad@constellation.com
(410) 787-5226
COMMENTS:
Dear Drafting Team Members:
Thank you for the opportunity to offer input at this stage of the standard development. Below, please
find comments from Constellation Power Generation and Constellation Commodities Group (collectively
CPG):
1. How can the proposal outlines in the White Paper be improved? Is the drafting team heading in
the right direction?
CPG agrees with many of the aspects discussed in the White Paper such as on page 3
“...qualifying generator interconnection facilities should be classified as transmission. That does
not, however, mean that a Generator Owner or Generator Operator should be required to
automatically register as a Transmission Owner or Transmission Operator simply because it
owns and/or operators transmission Elements or Facilities” and that “requiring any classification
that subjects Generator Owners and Generator Operators to all the standards applicable to
Transmission Owners and Transmission Operators would do little, if anything, to improve the
reliability of the Bulk Electric System.” CPG also agrees with the limited number of proposed
reliability standard changes that this drafting team has identified in the White Paper.
However, the White Paper also states that any potential reliability gaps can be closed by
“properly applying standards or specific standard requirements to Generator Owners and
Generator Operators.” CPG does not agree with that statement. Applying selected
requirements or standards to all GOs and GOPs when any potential reliability gaps only apply to
a minority of GOs and GOPs is not the correct approach.
The proposed White Paper departs from some of the valuable concepts within the Ad Hoc
Group report from November 2009, which CPG would like to see reconsidered. The drafting
team should revisit the Ad Hoc report recommendation to define “Generator Interconnection
Facility”. Because generator interconnection facilities are distinctly different from the
traditional transmission function understood within the Bulk Electric System, generator
interconnection facilities should be independently defined. Once clearly defined, the drafting
team should consider the subset of transmission geared standards useful to address reliability
issues at the subset of applicable GOs and GOPs.
The draft definition language in the Ad Hoc Report offers a good starting point:
Generator Interconnection Facility
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Sole-use facility for the purpose of connecting the generating unit(s) to the
transmission grid. In this regard, the sole-use facility only transmits power
associated with the interconnecting generator, whether delivered to the grid or
delivered to the generator for station service or auxiliary load, or delivered to
meet cogeneration load requirements.
Generator Interconnection Operational Interface
Location at which operating responsibility for the Generator Interconnection
Facility changes between the Transmission Operator and the Generator
Operator.
2. The drafting team has chosen to use informal means of receiving industry feedback (webinars,
presentations before industry stakeholder groups, etc) prior to expending valuable industry
resources to develop specific proposals for reliability standard requirements, measures, VSLs,
etc. Do you have any further suggestions for seeking industry input before the project moves
into a more formal development phase?
Constellation supports use of informal feedback opportunities as part of the development
process. This allows for constructive input early in the process without the response obligations
of the formal steps which will take place later in the process. In addition, informal settings offer
industry members the chance to better understand the issues and decision making behind the
standard development and encourage greater familiarity with the proposal before it reaches
formal ballot.
3. The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface” as part of this project. The Project 2010-07
drafting team believes that changes to the definition of Bulk Electric System under Project 201007 and modifications to a select group of standards can accomplish the same goal without the
need for new definitions. Do you support this approach? If not, please explain.
CPG disagrees with this approach. The BES team is currently standardizing the definition of BES
using input from the regions and NERC. Its scope does not include creating new functional
models and changing standards to close any perceived gaps in reliability. The Ad Hoc team’s
proposal of creating new terms such as “Generator Interconnection Facility” is a much better
approach. By clearly defining that term, the small subset of GOs and GOPs that may have these
facilities can be made subject to the select TO requirements or standards to address the
potential reliability question.
Thank you for your consideration. Please contact me with any questions.
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Kurtis B. Chong, Independent Electricity System Operator
kurtis.chong@ieso.ca
905-855-6282
COMMENTS:
IESO Comments on Project 2010-07
“Generator Requirements at the Transmission Interface”
We thank the Project 2020-07 SDT for the opportunity to comment of the posted white
paper and attachments. IESO supports the effort to properly determine which TO/TOP
reliability standards requirements ought to apply to GO/GOPs to promote BES reliability,
while at the same time not burdening GOs/GOPs with the obligation of complying with
other requirements that are not relevant to their operation. We offer these comments:
The introduction to the white paper raised the question of classifying generating facilities,
including their generator interconnection facilities, to determine what level of reliability is
needed for such facilities. Further, on page 2, the SDT referred to “qualifying” generator
interconnection facilities. However, it is not clear what are the qualifying criteria. Are the
qualifying criteria for Elements and Facilities the BES definition criteria? If so, this should
be stated explicitly.
We agree with the proposed changes to FAC-001-0. An alternative approach would have
been to include the GO in each of requirements R1 to R3. That would however have meant
that the GO would have to document, maintain and publish facility connection
requirements even in cases where requests for same are unlikely. The proposed approach
makes compliance with R1 to R3 mandatory only upon receipt of a request and avoids
potentially unnecessary upfront work by the GO.
In FAC-001-0, we suggest that R4 be modified as follows: Start the sentence with “The” and
delete “be required to”.
We agree with the proposed changes to FAC-003. The last sentence of footnote 2 of FAC-003
should also be modified to include the Generator Owner.
The proposed definition of Generator Interconnection Operational Interface was “Location
at which operating responsibility for the Generator Interconnection Facility changes
between the Transmission Operator and the Generator Operator.” We do not understand
the SDT’s rational for removing this definition since it does not refer to Elements and
Facilities rated at 100 kV and above. It is also unclear how the original objective meant to be
achieved by the proposed change to EOP-008-0 R1.3 would be met. Please clarify.
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Sandra Shaffer, PacifiCorp
Sandra.Shaffer@PacifiCorp.com
COMMENTS:
PacifiCorp respectfully submits the following comments with respect to Project 2010-07:
Generator
Requirements at the Transmission Interface: White Paper for Informal Comment:
PacifiCorp generally agrees with the objective and purpose of Project 2010-07, namely, to
ensure that all generator-owned facilities that are considered part of the bulk electric
system(“BES”) are identified and that the level of reliability needed to operate such facilities is
appropriately covered under NERC’s Reliability Standards.
However, PacifiCorp believes that certain of the standard drafting team’s proposals are not
consistent with this objective.
Specifically, in “Proposed Next Steps and Review of Reliability Standards,” item #3, the
standards drafting team proposes to ensure that the responsibility for generator
interconnecting line leads is appropriately and clearly assigned to Generator Owners and
Generator Operators. PacifiCorp believes that this step is not necessary at this time and is
inconsistent with the purpose of Project 2010-07. The purpose of the project is to ensure that
the facilities considered part of the BES are properly identified. The definition of “BES” should
define the facilities that are part of the BES; it should not define responsibility or ownership of
those facilities. Although typically generator lead lines are owned and operated by the
Generator Owner or Generator Operator, they may also be owned or operated by the
Transmission Owner or Transmission Operator. The BES definition should
remain broad enough to take this difference into account.
PacifiCorp disagrees that a requirement should be added to FAC-001-0 to require a Generator
Owner that receives an interconnection request for its facility to comply with requirements R1,
R2, and R3. First, it is not clear to PacifiCorp that the lack of this requirement could result in
gaps. The standards drafting team provides no support for the existence of such a gap and
rather simply makes an assumption that it could result in reliability gaps. PacifiCorp is not
aware of many generating facilities that, given FERC’s open access requirements, receive
interconnection requests. That said, PacifiCorp would admit that it is theoretically possible that
a Generator Owner would receive an interconnection request. If such a thing were to occur,
PacifiCorp believes that is unreasonable to require the Generator Owner to have facility
connection requirements in place within 45 days of such request. The Generator Owner should
only be obligated to develop such facility connection requirements if the interconnection
request will be granted and new third-party facilities will actually be interconnected to the
Generator Owner’s facilities. In this manner, the burden of developing such facility
connection requirements will only apply when necessary to enhance reliability.
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Annette M. Bannon, PPL Generation, LLC
ambannon@pplweb.com
610-774-2064
COMMENTS:
The following NERC registered entities have reviewed and endorse the EPSA comments on this
project.
NCR00882 Lower Mount Bethel Energy, LLC
NCR00883 PPL Brunner Island, LLC
NCR00886 PPL Holtwood, LLC
NCR00887 PPL Martins Creek, LLC
NCR00888 PPL Montour, LLC
NCR05329 PPL Montana, LLC
Thank you for considering the industry's comments on the Generator Requirements at the
Transmission Interface White Paper.
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Natalie McIntire, American Wind Energy Association
natalie.mcintire@gmail.com
651-964-2599
COMMENTS:
American Wind Energy Association
Informal Comments on NERC Project 2010-07
Generator Requirements at the Transmission Interface
The American Wind Energy Association (AWEA) appreciates the opportunity to
submit comments on the NERC Project 2010-07 white paper (White Paper), “Generator
Requirements at the Transmission Interface.” AWEA supports the proposed plan from
the Generator Requirements at the Transmission Interface Ad Hoc Group (GOTO Ad
Hoc Group), which concludes that:
1. If Generator Interconnection Facilities operate at 100 kV or greater or are deemed
critical to the Bulk Electric System, it would make the Generator Interconnection
Facility part of the Bulk Electric System with respect to Generator Owner and
Generator Operator requirements but not for Transmission Owner or
Transmission Operator requirements.
2. A Generator Owner or Generator Operator that owns and/or operates a Generator
Interconnection Facility (that is, a sole-use facility that interconnects the generator
to the grid) need not be registered as a Transmission Owner or Transmission
Operator by virtue of owning or operating its Generator Interconnection Facility.
3. A Generator Interconnection Facility is considered as if it is part of the generating
facility specifically for purposes of applying Reliability Standards to a Generator
Owner or Generator Operator.1
The NERC Standard Development Team’s (SDT) White Paper appears to be
generally consistent with the recommendations of the GOTO Ad Hoc Group. While the
SDT explains that generator interconnection facilities should be classified as part of the
Bulk Electric System (BES), it also states that “(this) does not mean, however, that a
Generator Owner or Generator Operator should be required to automatically register as
a Transmission Owner or Transmission Operator simply because it owns and/or
operates transmission Elements or Facilities. … [T]hese are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk
power system.”
AWEA supports the SDT’s conclusion that “[w]hen the transmission Elements and
Facilities owned and operated by Generator Owners and Generator Operators are
nonnetwork/non-integrated transmission, applying all standards applicable to
Transmission Owners and Transmission Operators would have little effect on the overall
reliability of the Bulk Electric System.”
AWEA also supports the SDT effort to rework the proposal from the GOTO Ad Hoc
Group, not because of significant differences between ultimate goals, but to simplify this
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modification process by limiting the number of standards that need to be changed.
1 NERC, “Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface”, November 16, 2009, Page 3.
We note, however, that the SDT does not clarify how, or under what circumstances, a
Generator Owner or Operator will be exempted from registration as a Transmission
Owner or Operator and the corresponding requirements. The new proposed definitions
for the BES from Project 2010-17, Definition of Bulk Electric System, include the
interconnection facilities along with the facilities of individual generators or generation
plants. If these proposed changes are adopted, we think there needs to be clarification
as to whether that would exempt GO/GOPs from the requirements that TO/TOPs.
Therefore, AWEA requests greater clarification of how, by definition or through
registration criteria, the SDT intends to implement the recommendation that a GO/GOP
should not be registered as a TO/TOP solely due to its interconnection facilities.
AWEA reads the White Paper to state there are few requirements that currently apply
to TO/TOPs that the SDT believes are critical enough that they should also apply to
GO/GOPs who have related interconnection facilities that qualify as part of the BES.
These include requirements related to registration of facilities that receive
interconnection requests, as well as vegetation management requirements that typically
apply to transmission facilities. AWEA details our concerns about both of these
requirements below.
FAC-001-0 – Facility Connection Requirements
Given the inconsistent understanding of which interconnection facilities are required to
offer interconnection or transmission service, AWEA urges the SDT to watch how this
issue unfolds at FERC,2 and to ensure that the additional requirements proposed in
FAC-001 apply only to generators who are required to accept interconnection requests.
Our concern is that a generator owner of interconnection facilities would be required to
incur costs and devote staff time to developing the facility connection requirements as
stated in FAC-001, even though a submitted request might not result in another party
interconnecting.
FAC-003-02- Transmission Vegetation Management
Given that this standard applies to lines 200kV and higher, it will apply only to
the largest interconnection facilities. Still, AWEA believes the vegetation requirements
the SDT has proposed in FAC-003 may be excessive for interconnection facilities that
are of limited length. Wind generators by their very nature are intermittent and,
therefore, are not relied upon in the same way as other generators with regard to the
reliability of the grid. Vegetation issues that cause problems with wind generator
interconnection facilities will not threaten reliability, but will only limit the ability for the
generator to deliver its output to market, which is no different than the situation when
the wind is not 2 A recent FERC Technical Conference on Priority Rights to New ParticipantFunded Transmission Projects, on March 15, addressed the question of when and how a
generator owner of an interconnection facility must receive an interconnection. It is possible that
additional rules may come out of this process to clarify these issues.
blowing. AWEA urges the SDT to consider limiting application of this requirement to
longer interconnection facilities, such as those that of . mile or more.
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John Criner, Kelson Energy, Inc.
crinerj@dicksteinshapiro.com
(202) 420-4714
COMMENTS:
Comments of Kelson Energy, Inc. (“Kelson”) on
White Paper Proposal for Informal Comment in Project 2010–07: Generator
Requirements of the Transmission Interface (“White Paper”)
Kelson supports the proposition set forth in the White Paper that a Generator
Owner (GO) or Generator Operator (GOP, collectively GO/GOP) should not be required
to automatically register as a Transmission Owner (TO) or Transmission Operator
(TOP) “simply because it owns and/or operates transmission Elements or Facilities.”1
However, the White Paper does not address this important registration issue. Kelson
understands that this is the result of the procedural limitations of the Project 2010–07
Standards Drafting Team (SDT), meaning that the SDT cannot propose changes to the
NERC Statement of Compliance Registry Criteria (Registry Criteria), but may only propose
changes to Reliability Standards. However, the result is that this registration issue is
still not being resolved by NERC in any public process. The SDT makes proposals to
add GO requirements, yet it remains uncertain how GO/GOPs will be treated with
respect to the TO/TOP requirements. Kelson believes this should be addressed as a
whole. For this reason, Kelson provides comments on how the registration issue should
be addressed, in addition to providing specific comments on the SDT’s proposals.
I. Registration
Kelson recommends that the SDT propose a new definition to the NERC
Glossary for “Generator Interconnection Facility” (GIF), as was proposed in the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface
(GO/TO Final Report) as follows:
Sole‐use facility for the purpose of connecting the generating unit(s) to the transmission
grid. In this regard, the sole‐use facility only transmits power associated with the
interconnecting generator, whether delivered to the grid or delivered to the
generator for station service or auxiliary load, or delivered to meet
cogeneration load requirements.2
In addition, Section III of the Registry Criteria should be revised to exclude an
entity that owns and/or operates GIF as their only transmission facilities from
registration as a TO and/or TOP as follows:
1White Paper at 3.
2GO/TO Final Report at 17.2
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Section III of the Registry Criteria states that the entities that meet the definition of
the different registration categories, including TO and TOP, should be excluded from
registration if they do not meet any criteria listed in Section III. The criteria listed for
TO and TOP in Section III is currently set forth as follows:
III.d.1 An entity that owns/operates an integrated transmission element associated with
the bulk power system 100 kV and above, or lower voltage as defined by the Regional
Entity necessary to provide for the reliable operation of the interconnected transmission
grid; or
III.d.2 An entity that owns/operates a transmission element below 100 kV associated with
a facility that is included on a critical facilities list that is defined by the Regional Entity.
Kelson recommends that this be changed as follows:
III.d.1 An entity that owns/operates an integrated transmission element associated with
the bulk power system 100 kV and above, or lower voltage as defined by the Regional
Entity necessary to provide for the reliable operation of the interconnected transmission
grid, and not including a Generator Interconnection Facility; or
III.d.2 An entity that owns/operates a transmission element below 100 kV associated with
a facility that is included on a critical facilities list that is defined by the Regional Entity.
These changes would prevent entities being registered as TO and/or TOP solely
due to their Generator Interconnection Facilities. At the same time, the Registry Criteria
always gives a Regional Entity the ability to register entities that do not otherwise fit
within the Registry Criteria if it reasonably demonstrates that the entity is a bulk power
system owner, or operates, or uses bulk power system assets and is material to the
reliability of the bulk power system.3 Thus, if there is a unique situation that indicates a
GIF must comply with all of the TO and/or TOP requirements, a mechanism is available
for registration.
3Registry Criteria, Note 1.
3
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II. FAC-001
Kelson does not object to the addition of GO to the applicability section of FAC–
001, but objects to the content of R4. FERC requires that when a generator receives an
interconnection request from a nonaffiliate,4 it must file an Open Access Transmission
Tariff within 60 days of receiving that request. Kelson recommends that R4 be revised
to be more consistent with FERC’s policies, at least for those entities regulated by FERC.
Generator Owner that receives an interconnection request for its facility from a
nonaffiliated entity, as determined by FERC, shall, within 45 days of such a request after its
Open Access Transmission Tariff is accepted by FERC, be required to comply with
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requirements R1, R2 and R3 for the facility for which it received the interconnection
request. If the Generator Owner is not subject to FERC Open Access Transmission Tariff
requirements, then it shall be required to comply with the requirements R1, R2 and R3
within 45 days of such a request.
III. FAC-003
While Kelson agrees that vegetation management might need to apply to certain
generator interconnection facilities, particularly those of significant length,
indiscriminate application of FAC–003 to all GOs is not the appropriate solution. There
are significant differences between the facilities that make up part of the integrated
transmission grid and interconnection facilities—many, and sometimes all,
interconnection facilities are “inside the fence,” where all vegetation will have been
cleared as a matter of course. In this case, vegetation would not be an issue and
application of a standard like FAC‐003 would be an inappropriate and unnecessary
burden on the owner of the interconnection facilities. While R4.2.4 might exclude
entities with facilities inside the fence, even for facilities that extend beyond the fence,
any vegetation management standard must be flexible to accommodate variations since
interconnection facilities may consist of generator leads of varying lengths from a few
feet to many miles. A one‐size–fits‐all approach like FAC‐003 is not appropriate. The
vegetation management standard imposed on GOs should be less prescriptive than the
one applicable to TOs. Kelson proposes that a GO vegetation management standard
broadly require the GO to ensure that vegetation be maintained, and allowing the GO
to develop and implement an appropriate program for vegetation, depending on the
extent of vegetation within its right‐of‐way.
4Sky River, LLC, 134 FERC ¶ 61,064, at P 13 (2011).
4
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IV. Definition of Bulk Electric System (BES)
Kelson has no objection to relying on a new BES definition to ensure that the
responsibility for generator interconnection leads appropriately and is clearly assigned
to GO/GOPs with respect to the standards listed in the White Paper, so long as the final,
approved BES definition actually achieves this end. Otherwise, there will be a need to
clarify that the GO/GOP would need to include their generator interconnection facility
in their compliance activities for these activities. At the same time, waiting for the final,
approved BES definition to address this issue could prolong this process unnecessarily,
and therefore, Kelson suggests that the SDT propose to make the needed clarifications.
This could be done by changing the definition of GO to be defined as an “[e]ntity that
owns and maintains generating units, including its Generator Interconnection Facility”, as
recommended in the GO/TO Final Report.5 Alternatively, NERC could issue a
Compliance Application Notice clarifying that when a GO and/or GOP is implementing
the standards listed on pages 5‐6 of the White Paper, its compliance activities should
encompass the generator interconnection facilities.
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Dale Fredrickson, Wisconsin Electric
Dale.Fredrickson@we-energies.com
COMMENTS:
The efforts of the SDT are appreciated in support of reliable operation at the GeneratorTransmission interface. In particular, we believe that the SDT decision not to propose new
definitions or to change other existing definitions, and not to make changes to dozens of
standards is a good one. In this respect we fully agree with the direction of the SDT.
However, we take issue with other aspects of the white paper. First, we believe that the
statement (p. 4, Para. 3) that “requiring any classification that subjects Generator Owners and
Generator Operators to all the standards applicable to Transmission Owners and
Transmission Operators would do little, if anything, to improve the reliability of the BES”, is
not precisely true. Much greater, such a requirement would actually reduce reliability. The
costs and efforts to comply with these standards would displace time and money that could
have been invested in real reliability enhancements. This entire paragraph needs more
clarity. The second sentence appears to say much the same as the first, but it qualifies the
Generator Owner/Operators “transmission Elements and Facilities” as those which are
nonnetwork/non-integrated. It is unclear just what statement is being made here, especially about
whether any Generator Owner/Operators “transmission Elements and Facilities” would
indeed be considered network/integrated. Our understanding is that by definition, these
Elements and Facilities (generator tie lines) are not network lines in the sense that
Transmission Lines are network lines.
As for the Proposal #1 to add the GO to the Applicability section of FAC-001-0, Facility
Connection Requirements, we do not support this. The need for this is not apparent. We
suggest that there are few, if any, situations where there would be an interconnection request
directed to a Generator Owner. It is a unique characteristic of transmission systems that they
are the gatekeepers which establish connections for generation and load. We suggest this is
an unnecessary extension of a standard to Generator Owners, and is not required for
reliability.
Proposal #2 adds the Generator Owner to the Applicability section of FAC-003-2,
Transmission Vegetation Management. This is done across the board, with no criteria for
circuit length or where the circuit is located. We maintain this is much too broad, and will
result in inefficient allocation of resources. The FAC-003-2 standard appears to have very
demanding requirements for transmission right-of-way vegetation management and
substantial documentation requirements. The reliability risk of vegetation problems on tie
lines at the Generator-Transmission interface is almost zero. In cases where the affected
“transmission Elements and Facilities” is very short (in one case of ours, from the plant to the
switchyard on the opposite side of a street), or in cases where such facilities are on the
property of the Generator Owner, the requirement to comply with FAC-003 is not justified by
reliability risks, and we strongly object to this proposal. For these cases, the resources
required to comply with FAC-003 standard would be considerable. We propose that the SDT
implement the Material Impact Test suggested in the Ad Hoc Group’s Final Report
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(November 2009) Recommendation #3 (p. 10): “Modify the applicability of FAC-003-1 to
apply to Generator Owners when their Generator Interconnection Facility operates at 200 kV
or above and exceeds two spans (generally more than one-half mile, see p. 3, #6) from the
generator property line...”
We appreciate the work of the SDT, and the opportunity to offer our comments.
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Ed Davis, Entergy Services
EDAVIS@entergy.com
504-576-3029
COMMENTS:
ENTERGY COMMENTS
NERC PROJECT 2010-07
GENERATOR REQUIREMENTS TO THE TRANSMISSION INTERFACE
Informal Comment Period – Ending April 4, 2011
Ed Davis
504-576-3029
We suggest the following changes and additions to the proposed draft changes to FAC-001.
First, the proposed R4 states “ .. interconnection request for its facility..”. It would be clearer to us if the
request was stated as “to” its facility and suggest changing “for” to “to”:
R4. Generator Owner that receives an interconnection request for to its facility shall,
Second, the proposed change to FAC-001, addition of Requirement 4, will require the generator owner
to comply with FAC-001 Requirements 1-3 under certain conditions. Therefore, we suggest the following
changes to R1-3 to conform to the addition of R4:
R1. The Transmission Owner and/or Generator Owner shall document, maintain, and
publish facility connection requirements to ensure compliance with NERC Reliability
Standards and applicable Regional Reliability Organization, subregional, Power Pool,
and individual Transmission Owner and/or Generator Owner planning criteria and
facility connection requirements. The Transmission Owner’s and/or Generator
Owner’s facility connection requirements shall address connection requirements for:
R2. The Transmission Owner’s and/or Generator Owner’s facility connection requirements shall
address, but are not limited to, the following items:
R3. The Transmission Owner and/or Generator Owner shall maintain and update its facility
connection requirements as required. The Transmission Owner and/or Generator Owner
shall make documentation of these requirements available to the users of the transmission
system, the Regional Reliability Organization, and NERC on request (five business days).
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David K Thorne, Pepco Holdings, Inc. - PHI
dkthorne@pepco.com
302-283-5718
COMMENTS:
Pepco Holding Inc. Comments
PHI supports the general concepts and direction of the proposals as defined in the published white
paper.
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Gretchen Schott, BP Wind Energy North America Inc.
gretchen.schott@bp.com
713-354-2113
COMMENTS:
BP Wind Energy North America Inc. Comments on
Project 2010-07: Generator Requirements at the Transmission Interface
On Friday, March 4, 2011, the Project 2010-07 Generator Requirements at the Transmission Interface
drafting team posted for a 30-day informal comment period a white paper on proposed concepts to
support the modifications of various standards to clarify the reliability standard responsibilities of
Generator Owners and Generator Operators at the interface to the interconnected grid.
BP Wind Energy North America Inc. (“BP Wind Energy”) submits the comments set forth below on the
white paper. Various BP Wind Energy subsidiaries own and operate wind-powered generating facilities
throughout the United States and are registered with NERC as Generator Owners (“GOs”) and Generator
Operators (“GOPs”) in RFC, SPP, TRE, and WECC.
BP Wind Energy agrees with, and supports, the approach recommended in the white paper regarding
how to address the applicability of NERC reliability standard to GOs and GOPs that own and/or operate
generator interconnection facilities. While BP Wind Energy does not agree with the conclusion set forth
in the white paper that generator interconnection facilities should be classified as transmission, BP Wind
Energy strongly agrees with the white paper’s recommendation that a GO or a GOP that owns and/or
operates generator interconnection facilities should not automatically be registered as a Transmission
Owner (“TO”) or Transmission Operator (“TOP”) simply because it owns and/or operates such facilities.
Generator interconnection facilities are typically not part of the integrated transmission system and,
therefore, their reliable operation and maintenance should not require adherence to the same level or
scope of standards that are applicable to transmission facilities that are part of the integrated
transmission system. Indeed, requiring GOs and GOPs that own and/or operate generator
interconnection facilities to adhere to all NERC reliability standards that are applicable to TOs and TOPs
that own and/or operate transmission facilities that are part of the integrated grid makes little sense as
such an approach is likely to do little to increase or ensure reliability of the bulk power system, fails to
focus on what is needed to ensure reliable operation and maintenance of generator interconnection
facilities, and results in unnecessary increased costs and burdens on GOs and GOPs.
By contrast, BP Wind Energy believes that the targeted approach recommended in the white paper –
i.e., to clarify the applicability of a select number of reliability standards to GOs and GOPs by modifying
the Purpose, Functional Entity section, requirements, and measures – is a better way to address reliable
operation and maintenance of generator interconnection facilities and one that should go a long way
toward providing clarity to the industry (and, in particular, GOs and GOPs) regarding GO and GOP
reliability obligations.
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However, given the targeted nature of the approach, BP Wind Energy strongly urges the drafting team
to consider drafting and recommending, or recommending that NERC draft, revisions to the Statement
of Compliance Registry Criteria that clarify the criteria for registration applicable to generator entities
that own and/or operate generator interconnection facilities to ensure that, going forward, GOs and
GOPs that own and/or operate such facilities are not improperly registered as TOs and TOPs. GOs and
GOPs need to have the solution documented and applied in a consistent manner across regions.
Moreover, BP Wind Energy disagrees with the changes that the SDT is proposing be made to FAC-001-0.
As BP Wind Energy reads the proposed changes, any GO that receives a request for service over a
generator interconnection facility in which the GO has an ownership interest would be required be
comply, within 45 days of receiving such a request, with the requirements set forth in R.1., R.2., and R.3.
of FAC-001-0. Those requirements would obligate a GO to publish facility connection requirements for
its generator interconnection facility and to ensure that the requirements address, among other things,
procedures for coordination of joint studies of new facilities and their impacts on the interconnected
transmission systems.
The Federal Energy Regulatory Commission (“Commission”) is in the midst of considering issues related
to priority access rights relating to participant-funded transmission projects, including those related to
generator interconnection facilities (in particular, generator lead lines), as evidenced by the technical
conference held by Commission staff on March 15, 2011 and the Commission’s request in Docket No.
AD11-11-000 for the submittal of comments by April 21, 2011 on such issues. As a result, the
requirements applicable under Commission policy to a generator that receives a request for service over
a generator interconnection line are likely to be revised or, at the very least, clarified by the Commission
within the next year.
While it is difficult to predict what changes or clarifications the Commission might make, it is very
possible that such changes or clarifications will conflict with the requirements set forth in FAC-001-0.
For example, the Commission might establish a safe harbor period during which a generator would be
permitted to have priority access over the use of the generator interconnection line and would be able
to decline to provide service over the generation interconnection line. If the Commission were to adopt
this proposal and a generator were to receive a request for service during the safe harbor period, the
generator would be permitted to decline service under Commission policy but, under FAC-001-0, would
be required to publish facility connection requirements for service that it will not be providing. The
Commission could also establish a pro forma tariff governing service over generator interconnection
lines with terms and conditions of service that differ significantly from the Commission’s current pro
forma open access transmission tariff. If the Commission were to adopt this proposal and a generator
were to receive a request for service, the requirements of FAC-001-0 could end up requiring a generator
to adopt facility connection requirements that are not required under the pro forma generator
interconnection tariff and viewed to be more stringent, such as procedures for coordination of joint
studies.
In BP Wind Energy’s view, neither of these results makes sense from a compliance or reliability
perspective. BP Wind Energy therefore urges the SDT to either to not propose to add references to GOs
in FAC-001-0 or, alternatively, to ensure that any requirements imposed on a GO under FAC-001-0 are
consistent with, and not more stringent or in conflict with, Commission policy. At a bare minimum, the
proposed timeframe for imposing the requirements in FAC-001-0 on GOs that receive an
interconnection request should be changed to 60 or more days to be consistent with current
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Commission policy that requires a generator to file with the Commission an open access transmission
tariff within 60 days of receiving a request for service.
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Rebecca Baldwin, Transmission Access Policy Study Group
rebecca.baldwin@spiegelmcd.com
202-879-4088
COMMENTS:
Comments of the Transmission Access Policy Study Group on the White Paper Proposal
in Project 2010-07: Generator Requirements at the Transmission Interface
TAPS appreciates the opportunity to comment on the GO/TO drafting team’s White
Paper. We generally support the approach proposed in the White Paper but have some specific
suggestions.
We suggest that at minimum, this drafting team’s goal should be to give guidance as to
what Facilities are covered under a GO/GOP registration and therefore do not require TO/TOP
registration. For example, radial generator leads, including all Elements radial to the generator,
should be included in the entity’s GO/GOP responsibility and should not require TO/TOP
registration.
A.
Framework
As the White Paper acknowledges in footnotes 1 and 2, it refers to both the “Bulk
Electric System” and the “bulk power system.” Although, as noted in footnote 2 to the White
Paper, “bulk power system” is defined in Section 215 of the Federal Power Act, it is not a
NERC Glossary defined term; furthermore, “bulk power system” and “Bulk Electric System”
may or may not be synonymous terms. See Order 743-A, Paragraphs 61-63. While we
recognize that there are existing NERC documents that refer to the bulk power system, we
suggest for the sake of clarity and precision that going forward, so long as the contours of the
“bulk power system” are not clearly defined, NERC documents should use only the NERCdefined term “Bulk Electric System.”
One area in which the bulk power system is relevant is that FERC’s reliability
jurisdiction, and thus NERC’s authority, are limited to the bulk power system. Therefore, the
following statement on page 3 of the White Paper needs to be revised:
While qualifying Generator Owners and Generator Operators can
be classified as owning and operating electric transmission
Elements and Facilities, these are most often not part of the
integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power
system.
Mandatory reliability standards—even a lower level of standards—cannot apply to nonBPS elements. It would be more accurate to state that generator leads do not exhibit many of the
characteristics, such as integration, that require application of the full set of TO/TOP reliability
standards to most transmission.
We believe that generator leads that are needed for reliability are already considered part
of the BES because they are not “radials serving only load.” Under Order 743, the BES must
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include whatever is “necessary for reliable operation of an interconnected transmission grid,”
which likely means that those generator leads that connect BES generators will continue to be
part of the BES. Therefore, the issue facing the GO/TO team is primarily one of registration, not
BES definition: BES generator interconnection facilities should be considered BES Facilities as
they are now, but where the generator lead is owned/operated by the GO/GOP (which is not
always the case), it should be included in the GO/GOP’s registration and should not subject the
GO/GOP to registration as a TO/TOP. Note that BES Definition SDT is not assigning
responsibility for BES Facilities to one functional entity or another.
We note in addition that the White Paper’s statement that “[w]hile not all power plants
are considered part of the Bulk Electric System, ultimately, all the plants are interconnected to
the bulk power system via their generator interconnection facilities” (emphasis added) is
incorrect due to the italicized language. In fact, some plants are connected to distribution or nonBES sub-transmission and are not connected to the bulk power system or BES through their
interconnection facilities.
TAPS’ overarching concern is that a system that only owns a minor component of a
generator lead should only be registered and made responsible for those requirements and
measures of standards that properly apply to that component.
B.
Standards
TAPS is comfortable with the White Paper’s elimination of many of the standards
revisions that had been included in the GO/TO Ad Hoc Group Final Report. We believe that
clarifying that (a) generator leads connecting BES generators are BES Facilities, and (b) such
generator leads are included in the GO/GOP responsibilities of the owner and operator of the
generator, will eliminate much if not all of any reliability gap that exists.
Furthermore, there is no need to revise FAC-003 so that it applies to generator
interconnection facilities. A radial line cannot cascade, so the only effect of the radial generator
lead sagging into vegetation is that the generator becomes unavailable. Because generators
become unavailable for other reasons that dwarf the incidence of unavailability due to line
outages, and the generator’s unscheduled unavailability is therefore planned for, no reliability
purpose would be served by applying FAC-003 to generator interconnection facilities.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Michelle D’Antuono, Occidental Energy Ventures Corp
Michelle_DAntuono@oxy.com
COMMENTS:
Occidental Energy Ventures Corp. Comments on NERC Project 2010-07 White Paper Proposal on
Generation Requirements at the Transmission Interface (GRTI)
Occidental Energy Ventures Corp.(“Oxy:) commends the GRTI Standard Drafting Team (and the previous
Ad Hoc GOTO group) for its efforts to define the NERC Standards requirements that should apply to
generation interconnection facilities and offers the following answers to the questions posed in the
informal comments announcement:
The Ad Hoc group originally proposed the new terms “Generation Interconnection Facility” and
“Generation Interconnection Operational Interface” as part of this project. The Project 2010-07
drafting team believes that the changes in the definition under Project 2010-17 and modifications to a
select group of standards can accomplish the same goal without the need for new definitions. Do you
support this approach? If not, please explain.
1. Coordination Between Standard Drafting Teams. Based on the current status of the Bulk Electric
System Standard Drafting Team (BESSDT) proposed BES definition, the White Paper Proposal
(“Proposal”) does not provide a clear demarcation between generator interconnection facilities and the
interconnected transmission facilities of the Transmission Owner/Operator. The current BES definition
makes no mention of what is or is not generation interconnection facilities, but merely includes
“generating units greater than 20 MVA (aggregated 75 MVA at one site) from the generator terminals
through the GSU which has a high side voltage of 100 KV or above.” Many such registered generators
have an additional interconnection line that is above 100 KV that, in turn, connects the generator to the
transmission owner’s facilities and is part of the generator interconnection. The currently proposed BES
“core definition” would classify this line as a Transmission Element and might be construed as subjecting
the GO to the full array of TO/TOP standards for this interconnection line. This outcome would violate
the stated purpose of the Proposal. According its scope, the BESSDT is looking to the GRTISDT to define
this demarcation either through a definition, as proposed by the Ad Hoc group, or by some other means.
As Oxy interprets its scope, the BESSDT is defining what is or is not part of the BES without defining what
standards apply to different parts of the BES, or, for that matter, what standards apply to non-BES
facilities.
2. Generation Interconnection Lines. Oxy basically disagrees that generation interconnection lines are
transmission lines from a functional standpoint. The interconnection line’s function is to interconnect
the generator (i.e., generally radial in nature) with the transmission system. The transmission system
function is to deliver the generation to the load. That is not to say that some standards related to higher
voltage lines may apply. Merely that, from a functional standpoint, the two are not the same and the
reliability requirements are not the same.
How can the proposal outline in the White Paper be improved. Is the drafting team headed in the
right direction?
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In general, the approach outlined in the White Paper needs more clarity concerning exactly what
requirements will apply to the essentially radial systems connecting generation to the transmission
system. This needs to be very clear. Oxy suggests that the Ad Hoc approach of defining Generation
Interconnection Facilities be adopted by the drafting team (although the Ad Hoc definition is probably
not adequate). The drafting team will then have to decide whether their proposed definition provides
enough clarity such that there will be no doubt that most of the TO/TOP standards do not apply to these
facilities. The TO/TOP standards that would apply to interconnection facilities would then be treated
individually with new/revised requirements.
1. Proposed FAC-001 Revisions. The proposed addition of R4 and M4 in FAC-001 seems to be stated in
reverse. Wouldn’t the normal procedure be for the GO to submit an interconnection request to the
TO as part of entering into an interconnection agreement? The procedure required of the TO in R1
through R3 specify what the TO’s requirements are for interconnection. As an aside, as these
procedures are changed or updated, there needs to be some requirement for communication of the
changes. Also, Oxy questions the 45 day requirement. How could all the requirements in the
interconnection procedure be accomplished in 45 days? The drafting likely has some underlying
assumptions that are not apparent and need clarification.
2. Proposed FAC-003 Revisions. Oxy agrees with the Ad Hoc Group’s Proposal 2 which provides for
exclusions for short distance interconnections, i.e., interconnection lines that do not exceed two
spans (or some reasonable distance that can be monitored visually or with cameras) from the
generator’s property line. In addition, there should be a process for demonstrating to the Regional
Entity that the interconnection line has no vegetation around it to manage, i.e., in arid or industrial
locations.
Do you have any further suggestions for seeking industry input before the project moves into a more
formal development phase?
Oxy feels the comments on the Ad Hoc group report and the comments on the Proposal provide
sufficient information for the drafting team to commence formal development. Although this project is
extremely important, the formal process should not be shortened by classification as urgent.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Greg Rowland, Duke Energy Corporation
Greg.Rowland@duke-energy.com
COMMENTS:
Below are Duke Energy comments on the currently posted White Paper:
Questions posed on the NERC Announcement, and Duke Energy Responses
1. How can the proposal outlined in the White Paper be improved? Is the drafting team
heading in the right direction?
Response: Duke Energy agrees with the approach outlined in the White Paper, which is to
rely on the definition of Bulk Electric System (now being revised on Project 2010-17) to
ensure that all BES facilities are appropriately identified for applicability of reliability
standards. This is a much cleaner approach than the previous effort. We appreciate the
work of the Standard Drafting Team to use this targeted approach to identifying the
specific reliability standards which should be applied to Generator Owners and Generator
Operators for their BES interconnection facilities.
2. The drafting team has chosen to use informal means of receiving industry feedback
(webinars, presentations before industry stakeholder groups, etc.) prior to expending
valuable industry resources to develop specific proposals for reliability standard
requirements, measures, VSLs, etc. Do you have any further suggestions for seeking
industry input before the project moves into a more formal development phase?
Response: No further suggestions for seeking industry input.
3. The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility”
and “Generator Interconnection Operational Interface” as part of this project. The Project
2010-07 drafting team believes that changes to the definition of Bulk Electric System under
Project 2010-17 and modifications to a select group of standards can accomplish the same
goal without the need for new definitions. Do you support this approach? If not, please
explain.
Response: Duke Energy agrees that the previously proposed new defined terms are not
needed. Project 2010-17 is developing a definition for Bulk Electric System (BES) that uses
a bright-line criteria of 100 kV and above, and an inclusion/exclusion process to address
specific facilities. This will ensure that BES interconnection facilities are appropriately
identified. If Project 2010-07 then identifies any modifications to the reliability standards
needed to address specific responsibilities of Generator Owners and Generator Operators
to BES interconnection facilities, then no “reliability gap” will exist.
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Generator Requirements at the Transmission Interface - Project 2010-07
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May 18, 2011
Kenneth A. Goldsmith P.E., Alliant Energy
319-786-4167
KenGoldsmith@alliantenergy.com
COMMENTS:
We have one comment concerning making a Generator Owner (GO) subject to the requirements of
FAC-003 Transmission Vegetation Management. We can understand the need to have long
highvoltage radial lines from a generating station to the interconnection point of the BES be
included in the requirements for FAC-003. Our concern lies with the lines from a central generating
station GSU, normally located just outside the generator building to the substation which may not
be directly adjacent to the power block. These lines typically remain within the generating station
boundaries, so we believe Article 4.2.4 of FAC-003-2 should be revised to read : “. . . located
outside the fenced area of the switchyard, generating station property or substation and any
portion of the span of the . . .”. This would clarify that only lines outside of the generating station
property would be applicable.
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May 18, 2011
Lee Pedowicz, NPCC
lpedowicz@npcc.org
COMMENTS:
Below are NPCC’s comments for Project 2010-07 - Generator Requirements at the Transmission
Interface - Various BAL, CIP, EOP, FAC, IRO, MOD, PER, PRC, TOP, and VAR Standards. The table lists
the NPCC member contributors to these comments.
Member
Organization
Region
Segment
Selection
1
Adamson, Alan
New York State Reliability Council, LLC
NPCC
10
2
Guy Zito
Northeast Power Coordinating Council
NPCC
10
3
Campoli, Gregory
New York Independent System Operator
NPCC
2
4
Chong, Kurtis
Independent Electricity System Operator
NPCC
2
5
Clermont, Sylvain
Hydro-Quebec TransEnergie
NPCC
1
6
Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
7
De Graffenried, Chris
Consolidated Edison Co. of New York, Inc.
NPCC
1
8
Dunbar, Gerry
NPCC
NPCC
10
9
Evans-Mongeon, Brian D.
Utility Services
NPCC
8
10
Garton, Mike
Dominion Resources Services, Inc.
NPCC
5
11
Gooder, Brian L.
Ontario Power Generation Incorporated
NPCC
5
12
Goodman, Kathleen
ISO - New England
NPCC
2
13
Haswell, Chantel
FPL Group, Inc.
NPCC
5
14
Kiguel, David
Hydro One Networks Inc.
NPCC
1
15
Lombardi, Michael R.
Northeast Utilities
NPCC
1
16
MacDonald, Randy
New Brunswick Power Transmission
NPCC
1
17
Metruck, Bruce
New York Power Authority
NPCC
6
18
Pedowicz, Lee
NPCC
NPCC
10
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May 18, 2011
19
Pellegrini, Robert
The United Illuminating Company
NPCC
1
20
Saksena, Saurabh
National Grid
NPCC
1
21
Schiavone, Michael
National Grid
NPCC
1
22
Sipperly, Wayne
New York Power Authority
NPCC
5
23
Weaver, Donald
New Brunswick System Operator
NPCC
2
24
Wu, Ben
Orange and Rockland Utilities
NPCC
1
25
Phan, Si Truc
Hydro-Quebec TransEnergie
NPCC
1
It is missing a logistical requirement between FAC-003 and FAC-014. There is nothing in
either standard where the PC is informing the TOs and GOs of the applicability of their
facilities as outlined in the Facilities section 4.2.2 of FAC-003.
· On page 3 of the White Paper, the SDT referred to “qualifying” generator interconnection
facilities. It is not clear what are the qualifying criteria. Are the qualifying criteria for
Elements and Facilities the BES definition criteria? If so, this should be stated explicitly.
· The proposed definition of Generator Interconnection Operational Interface was “Location
at which operating responsibility for the Generator Interconnection Facility changes
between the Transmission Operator and the Generator Operator.” Why was this definition
removed? It does not refer to Elements and Facilities rated at 100 kV and above. It is also
unclear how the original objective meant to be achieved by the proposed change to EOP008-0 R1.3 would be met. This needs clarification.
· In FAC-001-0, suggest that R4 be modified as follows: start the sentence with “The” and
delete “be required to”.
· The modification in FAC-001 for a Generator Owner is not necessary. It is understood that
a generator’s output connection to the transmission system must comply with the
“receiver’s” requirements.
· Interconnection request needs to be defined. In R4, why does the Generator Owner
receive an interconnection request?
· The last sentence of footnote 2 of FAC-003 should also be modified to include the
Generator Owner.
· For FAC-003, this appears to be a standard applicability and registration issue. It may be more
appropriate to define transmission in such a way that any generation owner that happens to
also own BES transmission must register as such. With the coming of the new BES definition
perhaps that would be the opportune time to introduce a fix for this registration issue. It is
suggested that with the upcoming changes to the BES definitions this project should be on
hold, with the understanding that the registration issue be examined.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
John Bee, Exelon Transmission Strategy & Compliance
(630) 576-6925
john.bee@exeloncorp.com
COMMENTS:
Project 2010-07 Exelon Comments
FAC-003
1. The SDT should include a unique schedule and guidance specifically for GO implementation of
this standard.
2. The standard should provide a clear provision to allow incorporating GO owned facilities within
an existing TO's vegetation management program if mutually agreed on by the TO and GO.
3. Please provide more clarification regarding FAC-003 Requirement 4.2.4. The rationale explains
that areas within the fenced area of a switchyard, station or substation and any portion of the
span of the transmission line that is crossing the substation fence are excluded; however, there
is no guidance regarding transmission lines that run between a generator main power step up
transformer and an onsite switchyard. Is the intent to include transmission lines on station
property that run between a generator main power step-up transformer and an onsite
switchyard?
4. Exelon suspects that this standard work is being done due to issues with GOs that have long
generator leads running miles rather then feet. The standard should have verbiage stating that
the standard is not applicable to GOs with short generator leads. The SDT should define “long
leads’ based the length of the conductor and have provisions to exclude generators with “short
leads”
FAC-001
1. Exelon does not agree that this standard should not be broadly applied to GO. GOs who do not
own a switchyard and whose point of interconnection is a disconnect switch associated with the
generator leads prior to the switchyard should be excluded from this standard. If a group of
GOs share a generator tie line, then the associated Interconnect Agreement that each of the GO
has with the applicable TO and/or TOP should address how these shared connections will effect
the system. GOs may not have the resources or expertise to conduct the required interconnect
studies to meet this standard
2. Exelon has generating stations that have the Main Power Transformer (MPT) disconnect as the
point of demarcation. The station owns the short leads from the MPT disconnect back to the
generator and the applicable TO owns from the MPT disconnect up to and including the
switchyard. It is not practical for another entity to request to interconnect to the MPT
disconnect nor should it be allowed. The SDT should consider verbiage to the standard that
does not allow requests to interconnect to a MPT disconnect.
3. Exelon is having difficulty determining how this standard would apply to GOs and how GOs
would implement the standard; suggest that examples be provided in an implementation
document specifically showing where and how this standard would apply.
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Summary Comment Report
May 18, 2011
Patti Metro, National Rural Electric Cooperative Association (NRECA)
703.907.5817
patti.metro@nreca.coop
COMMENTS:
Drafting Team Members,
The National Rural Electric Cooperative Association (NRECA) thanks the team for this
opportunity to provide comments to its white paper. Although, NRECA supports clarifying
the responsibilities of entities that own/operate transmission and/or generation intertie/
interconnection facilities, until the definition of the Bulk Electric System under Project
2010-17 is developed it is difficult to rectify these issues. The team should carefully monitor
the Project 2010-17 activities to ensure that it does not adversely affect the success of the
project nor develops requirements or definitions that would contradict the criteria
established in Project 2010-17. At this time, NRECA does not have a specific position on
these issues, but looks forward to reviewing and commenting on future documents this
team posts for stakeholder comment.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Ramiro Cerecer, Equipower Resources Corporation
(860) 656 0843
rcerecerr@eqpwr.com
COMMENTS:
Re: Project 2010-07 Generator Requirements at the transmission interface. Informal comment
period
EquiPower Resources Corp., its subsidiaries Dighton Power, LLC, Lake Road Generating Company,
L.P., MASSPOWER, Milford Power Company, LLC and its affiliate, Empire Generating Co, LLC
(collectively “EquiPower”) are pleased to submit these informal comments to the Project 2010-07
Standard Drafting Team (SDT). EquiPower own and operates five (5) power plants located in
Massachusetts, Connecticut and New York that are individually registered as Generator Owners (GO)
and/or Generator Operators (GOP).
EquiPower generally supports the SDT’s approach presented in its White Paper and believes the SDT is
heading in the right direction. The recommendations appear to be reasonable. In particular, we support
the following concepts and recommendations:
•
Neither a GO or GOP should be required to automatically register as a Transmission Owner (TO)
or Transmission Operator (TOP) simply because it owns and/or operates generator
interconnection facilities. Clarification of the fact that generator interconnection facilities are not
part of the integrated transmission system or grid is crucial to resolving the treatment of GO/GOP
interconnection facilities.
•
Subjecting a GO/GOP to all requirements in the TO/TOP standards is impractical and an
inefficient use of resources and will not have the desired effect of improving the reliability of the
Bulk Electric System (BES).
•
We support the recommended plan to modify a selected group of standards to make them
applicable to GO/GOP’s as they relate to their generator interconnection facilities. Subject to the
considerations described below, EquiPower supports the modification of both FAC-001-0
Facility Connection Requirements and FAC-003-2 Transmission Vegetation Management
Program.
•
EquiPower agrees that GO/GOP personnel training should be addressed in a future project.
EquiPower has two concerns that it asks the SDT to consider.
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May 18, 2011
•
First, as proposed in the GOTO Ad Hoc Group’s Final Report, EquiPower feels strongly that
including a defined span criteria at FAC-003-2 is important. Many generating plants have a
nominal length of overhead tie line extending from the generator step-up (GSU) transformer
substation to the interconnection point with the integrated transmission system. Requiring a GO
to have a vegetation management plan for such a nominal length of conductor is not practical or
efficient, nor does it provide any discernible benefit in terms of improving the reliability of the
BES.
•
Second, we are concerned about the regulatory implications associated with the identification of
generator interconnection facilities as transmission facilities or elements. The proposed addition
of Generator Owner to FAC-003-2 is similar to the applicability language found in PRC-023-1
Transmission Relay Loadability. Yet in Order 733 FERC concluded that, in the majority of cases,
a GO would not be subject to the standard since the GO would also need to be registered as a TO,
which FERC acknowledged is uncommon. The reasoning applied in Order 733 seems to focus on
the term “transmission lines” and that a transmission line owner, irrespective of integrated versus
non-integrated status, would need to register as a TO. EquiPower would encourage the SDT to
fully consider the implications of Order 733 as it applies to GOs and clarify the application of the
term “transmission lines.” It is fundamentally important that the use of the term “transmission
lines” clearly distinguish between integrated and non-integrated applications.
EquiPower appreciates the opportunity to submit these comments. The use of informal means of
communicating such as stakeholder webinars, meetings and comment submission are effective and
efficient tools for communication and standard development.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Eric Salsbury, Consumer’s Energy
(517) 788-7076
etsalsbury@cmsenergy.com
COMMENTS:
Following are the comments for Consumers Energy (NCR00740) regarding Project 2010-07.
Problems are created with the interchangeable use of "BES" and "transmission."
NERC should maintain consistency with the use of BES, Transmission, transmission, distribution,
etc. When a capitalized term is used it should be consistent with the NERC Glossary. Maybe a
note should also be provided to denote that the use of the term transmission and distribution
specifically do not refer to any defined system and are only used as part of the English
language. When a term is used in a standard maybe it should be used consistently throughout
the standard to avoid confusion. If it changes, even slightly, say to Bulk Power System (BPS) it
should be accompanied with an explanation why the term being used is different.
Transmission is defined by the FERC Seven Factors and by what has been authorized by the
regulating State body and the FERC as being Transmission. The term Transmission defined for
rate making purposes and Transmission systems vary significantly across the country to voltage
levels much less than 120kV. Therefore, the use of the term Transmission and the word
transmission should not be used to define facilities covered under NERC Reliability Standards.
Adding Registered Entities (GO/GOP/DP) to standards involving BES facilities should be allowed
to ensure the full coverage of BES facilities for the NERC Reliability Standards.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Joseph DePoorter, Madison Gas and Electric Company
608.252.1581
jdepoorter@mge.com
COMMENTS:
Within the Project 2010-07's White Paper, it should be noted that many GO's has established and
detailed Interface agreement concerning their Transmission Interfaces. This White Paper did not
clearly address those in place agreements. Recommend that this fact be highlighted going forward in
any such White Paper, Guideline, Rational box, etc.
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Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Carol Gerou, Midwest Reliability Organization
(651) 855 - 1735
ca.gerou@midwestreliability.org
COMMENTS:
The Midwest Reliability Organization’s NERC Standards Review Subcommittee submits the
following comments on the white paper titled “Project 2010-07: Generator Requirements at the
Transmission interface”:
SDT Question #1a: How can the proposal outlined in the White Paper be improved?
NSRS Responses:
Next Step #1 - According to FERC Docket #ER10-1117, if a Generator Owner receives a request for
service over their facilities; they have 60 days to file a tariff for processing the request for service.
So, we think that the proposed Requirement R4 of FAC-001 should give the Generator Owner 60
days, rather than 45 days, to provide its interconnection requirements.
Next Step #3 – NERC has not clearly defined wind farms to be generating plants. So, the words,
“directly connected via a step-up transformer(s) to Transmission Facilities operated at voltages of
100 kV or above”, in the latest Project 2010-17 concept paper may not be interpreted as applicable
to wind farms. The generating units of wind farms are typically directly connected to
subtransmission facilities, which in turn are directly connected to Transmission Facilities operated
at voltages of 100 kV or above.
Other proposed changes – in the paragraph about EOP-003-1 on page 6 we agree that Generator
Operators should not be added to EOP-003-01, but for a different reason. When the proposed
EOP-003-2 is approved and becomes effective, all of the requirements associated with the UFLS
programs will be removed. We don’t agree that PRC-001 already properly addresses the
coordination of the generator UF protection with the UFLS program. However, we understand
that the proposed PRC-024-1 will be the standard that contains the requirements for the
Generator Owners to coordinate generator UF with UFLS program.
******
SDT Question #1b: Is the drafting team heading in the right direction?
NSRS Response: Yes, the drafting team is heading in the right direction.
******
SDT Question #2: The drafting team has chosen to use informal means of receiving
industry feedback (webinars, presentations before industry stakeholder groups, etc.) prior to
expending valuable industry resources to develop specific proposals for reliability standard
requirements, measures, VSLs, etc. Do you have any further suggestions for seeking industry
input before the project moves into a more formal development phase?
NSRS Response: No
******
SDT Question #3: The Ad Hoc group originally proposed the new terms “Generator
Interconnection Facility” and “Generator Interconnection Operational Interface” as part of this
project. The Project 2010-07 drafting team believes that changes to the definition of Bulk Electric
System under Project 2010-17 and modifications to a select group of standards can accomplish the
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May 18, 2011
same goal without the need for new definitions. Do you support this approach? If not, please
explain.
NSRS Response: Yes
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Generator Requirements at the Transmission Interface - Project 2010-07
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May 18, 2011
Louis C. Guidry, P.E., Cleco Support Group LLC
318-484-7495
louis.guidry@cleco.com
COMMENTS:
FAC-003 should not be applicable to Generator Owners / Operators. The intent of all of the standards
is to avoid an Adverse Reliability Impact, or as the FPA Section 215(a)(4) defines “reliable operations”
as: “operating the elements of the bulk-power system within equipment and electric system thermal,
voltage and stability limits so that instability, uncontrolled separation, or cascading failures of such
systems will not occur as a result of a sudden disturbance, including a cybersecurity incident, or
unanticipated failure of system elements.” Radial Facilities serving only generating plants when tripped
will not threaten an Adverse Reliability Impact or we would be hard pressed to run that generation in
the first place.FMPA believes the intent of the standard is to prevent a cascading event where, if a line
trips, another line loads heavily increasing the sag of that line, which may sag into un-cleared
vegetation, causing the second line to trip, which may in turn cause heavily loading on a third line, etc.
If a line trips in the transmission network, radial Facilities from generating plants will not have their
loading changed much at all (since they are radial) and will not participate in this sort of “thermal”
cascading event. Hence, there is no cause to regulate vegetation management of radial Facilities to
generating plants since the system is always planned and operated to that potential contingency
anyway and there is no danger of an Adverse Reliability Impact. Regulating vegetation management on
radial Facilities is beyond the scope of the Federal Power Act Section 215.Generator Owners /
Operators are still incented to perform adequate vegetation management without the need for
regulation because any outage of the plant results in lost opportunity costs to the plant.
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Generator Requirements at the Transmission Interface - Project 2010-07
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May 18, 2011
Jonathan Hayes, Southwest Power Pool
1-501-614-3509
Jhayes@spp.org
COMMENTS:
Project 2010-07 Generator Requirements at the Transmission Interface
Attendance
Participants that Added Their Name to Comment Form
Group Comments (Complete this page if comments are from a group.)
Group Name:
SPP Standards Development
Lead Contact:
Robert Rhodes
Contact Organization:
Southwest Power Pool (SPP)
Contact Segment:
2
Contact Telephone:
501-614-3241
Contact E-mail:
rrhodes@spp.org
Additional Member Name
Additional Member
Organization
Region*
Segment*
Craig Henry
Oklahoma Gas & Electric
SPP
1,3,5
Michelle Corley
Cleco
SPP
1,3,5
Louis Guidry
Cleco
SPP
1,3,5
Sean Simpson
Board of Public Utilities, City of
McPherson, Kansas
SPP
1,3,5
Harold Wyble
Kansas City Power & Light
SPP
1,3,5
Alan Burbach
Lincoln Electric System
MRO
1,3,5
Gary Tarplee
Eddington Mission Marketing &
Training
SPP
5,6
Mark Wurm
Board of Public Utilities, City of
McPherson, Kansas
SPP
1,3,5
Stephen Layton
Mustang Station
SPP
Rick Koch
Nebraska Public Power District
MRO
1,3,5
Anthony Cassmeyer
Western Farmers
SPP
1,3,5
66
Eddie Perez
Generator Requirements at the Transmission Interface - Project 2010-07
Summary Comment Report
May 18, 2011
Wind Capital Group
SPP
FAC-001: What gaps have been identified? Since Generator Owners do not have a tariff how would a GO
determine what a valid interconnection request would be? The generator Owner wouldn’t have the
jurisdiction to accept an interconnection request any more than a land owner would. What is the basis
for making the Generator Owner the valid entity for accepting a request.
FAC-001 R4: This states that the Generator Owner must post within 45 days for an interconnection
request but the request should be a valid request. Generation Owners would not be a valid entity to
accept a generation interconnection request all requests should be submitted through the TSP.
Shouldn’t the TSP then provide notification to the GO when interconnection request are received to
interconnect with GO’s generation facilities? There are processes in place currently that handle valid
interconnection requests and this requirement seems to violate those processes. Could the Generator
Owner deny the request fr interconnection on his behalf? Since interconnection service only provides
interconnection to the Bulk Electric System and not transmission service how then will they acquire
transmission service? This requirement seems to conflict with current processes already in place.
FAC-003: Would like an expansion n the rationale behind why FAC003-2 should apply to ties outside of
the fence. It is in e best interest of the Generator Owner to take care of vegetation from his facility to
the BES in order to sell power.
BES Team: Would ask that the SDT would coordinate with the 2010-17’s SDT and keep these tied
together.
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Cindy Martin, Southern Company
p: 205.257.7573
ctmartin@southernco.
COMMENTS:
Mallory, please accept the below comments from Southern Company regarding Project 2010-07
White Paper: Generator Requirements at the Transmission Interface:
SoCo Gen Comments to Project 2010-07 White Paper:
Generator Requirements at the Transmission Interface
23 Mar 2011
General
We commend the effort directed towards the clarification of the application of NERC standards to
generation interconnection circuits (“extension cords”).
We agree completely with the following observations made on pages 2 and 3 of the White Paper
Proposal:
Power plants come in many sizes and configurations.
The (GOTO Ad Hoc Group) plan of proposing new definitions, modifying other definitions,
and making changes to dozens of standards is not necessary.
GOs and GOPs owning and operating electric transmission Elements and Facilities are most
often not part of the integrated bulk power system, and as such should not be subjected to
the same level of standards applicable to TOs and TOPs. [integrated implies networked,
“extension cord” implies radial]
Requiring any classification that subjects GOs and GOPs to all the standards applicable to
TOs and TOPs would do little to improve the reliability of the BES.
Applying all standards applicable to TOs and TOPs to non-networked/non-integrated
transmission circuits would have little effect on the overall reliability of the BES.
Changes to the definition of the BES and modifications to a select group of standards can
accomplish the goal without the need for new definitions.
FAC-001 R4
Please make it clear that the interconnection request is meant to be addressing a new connection
to the high voltage (>100kV) “extension cord” circuit owned by the Generator Owner.
The connection of additional generation or load to the “extension cord” generation
interconnection facility (circuit) changes the face of the non-radial nature of these circuits. It is not
clear that only FAC-001 and FAC-003 should be applicable to the GO/GOP with this interconnect.
Would the GO/GOP with networked transmission facilities be subjected to additional (traditional )
TO/TOP standard requirements? If so, this project should include a review of those standards in
the project scope.
Is the TO subject to completing R1, R2, and R3 within 45 days of receiving the interconnection
request? If not, should the GO be subject to that time constraint?
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Project 2010-07 Purpose
One of the two purposes of the Project 2010-07 is stated as “identify all generator-owned facilities
that are considered part of the BES” and “clearly identify the appropriate generation Facilities.”
Please focus on this identification process. This effort should ensure clarity in the scope of
application to GOs to avoid confusion and additional work load on GOs that do not contribute to
the reliability of the BES. We are concerned that the modified BES definition may make the
GO/GOP entities responsible for additional existing standards. A very clear description is needed to
identify which GO/GOP owned “extension cord” circuits are included. Also, there is a need for
itemizing any additional GO/GOP requirements resulting from a redefinition of the BES or from
changes to existing standards. These clear descriptions will help eliminate uncertainty regarding
the scope of equipment that is in the scope of NERC reliability standards.
Was any consideration given to creating a comprehensive listing of all NERC reliability standard
requirements for owners of these “extension cord” circuits? A document of this type would
provide GO/GOP owners of these circuits the ability to determine precisely which standards apply
to that equipment.
FAC-003-2
FAC-003-1 R1 should not include GO as generation interconnection facility (“extension cord”)
because they are never an IROL circuit.
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May 18, 2011
Thomas E. Foltz, American Electric Power
Reliability Standards Compliance
tefoltz@aep.com
COMMENTS:
American Electric Power (AEP) appreciates the opportunity to provide input to the draft of "Project
2010-07: Generator Requirements at the Transmission Interface", and offers the following response for
consideration.
AEP endorses the collective prior work of this group, however this effort needs to be done in
coordination with concurrent efforts already underway within NERC, in defining and re-defining
definitions that fall within the scope of the Bulk Electric System. It is unclear if lines are being drawn to
somehow delineate between what might be considered as the transmission portion of the bulk electric
system and what might be termed the generation bulk electric system.
We believe the group is heading in the right direction, however, in its implied desire to streamline the
required changes recommended by the GOTO Ad Hoc Group (by eliminating the definition of
Generation Interconnection Facility), it is now less clear where the planning and operational
responsibilities reside for the high voltage generator lead from the GSU to the transmission point of
interconnection. For example, page 3 of the White Paper states that the SDT believes it is appropriate
to classify various generating Facilities and Elements (including generator interconnection facilities) as
part of the Bulk Electric System. We agree. The SDT also states that it believes that qualifying
generator interconnection facilities should be classified as transmission. We do not agree with leaping
to classify the qualifying generator interconnection facilities as transmission absent further clarification,
particularly with respect to the definition of Generation plants that is the subject of Project 2010-07 as
explained in section 3 of the White Paper. Item 3 of section 3 states the following:
“Generating plants (including GSU transformers and the associated generator interconnection line
lead(s)) with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above:”
Item 3 helps to clarify what qualifying generation interconnection facilities fit within the Bulk Electric
System definition, but it is not at all clear from item 3 that the generation interconnection facility should
be classified at transmission. Indeed, the foregoing generating plant definition would appear to be at
odds with the SDT view.
This lack of clarity then brings into question the SDT groups conclusion that the “changes listed above
mark a significant decrease in changes originally proposed by the GOTO Ad Hoc Group in its Final
Report”. In particular, clarifications to the definition of Bulk Electric System eliminate the need for the
GOTO Ad Hoc Group’s suggestions to include a reference to the proposed new term “Generator
Interconnection Facility” in the following standards referenced in the GOTO Ad Hoc Group Final
Report: BAL-005-0.1b, CIP-002-1, EOP-001-0, EOP-004-1, FAC-008-1, FAC-009-1, IRO-005-2,
MOD-010-0, MOD-012-0, PRC-004-11, PRC-005-1, TOP-002-2, TOP-003-0, VAR-001-1, and VAR002-1.
While AEP agrees in principle that it is desirable to reduce the need for modifications to existing
Standards, we do not yet agree that the SDT’s White Paper brings enough clarity to reach the
conclusion that modifications to one or more of the foregoing Standards are not required.
The following comments are directed to the revisions the SDT team recommends to the following
Standards.
FAC-001
There are substantial reliability issues, as well as additional regulatory, tariff, coordination, and
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generator and interconnection facility issues, which need to be dealt with before AEP could agree to
such requirements. It is not clear that a generator can receive a request for interconnection. Typically
Generation Owners and/or developers make request for generation interconnection but do not have
OATT requirements or processes in place to receive requests for generation interconnection. A
material matter relating to the R4 requirement as defined by the SDT is whether a generator has any
obligation to interconnect a new generation facility to its high voltage generation interconnection facility.
This again points back to the SDT’s blanket statement that the BES qualified generation
interconnection facility be classified as “transmission”. We are not convinced this declaratory statement
comports with OATT and/or RTO generation interconnection procedures. Furthermore, it would be
onerous to expect a generator to agree to R4 since generators are not in a position to comply with R1,
R2 and R3.
FAC-001 R4
Regarding “Generator Owner that receives an interconnection request for its facility shall, within 45
days of such a request, be required to comply with requirements R1, R2, and R3 for the facility for
which it received the interconnection request.” Requirements R1, R2 and R3 refer to Transmission
Owner’s connection requirements. The proposed R4 as written implies the Generation Owner that
receives an interconnection request for its facility (what facility?) will comply with the Transmission
Owner facility connection requirements. We don’t see the linkage between the Generation Owner and
the Transmission Owner and how this is enforceable given the barriers to collaboration between new
and existing generators and transmission owners.
If an end user facility seeks to be served on the Generation side of an interconnect, shouldn’t the
request be coordinated through an entity such as the regional transmission entity, or the appropriate
transmission owner or transmission operator?
FAC-003-2
The SDT recommendation to add the Generation Owner requirement is acceptable.
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May 18, 2011
Kasia Mihalchuk, P. Eng., Manitoba Hydro
(204) 487-5434
kmihalchuk@hydro.mb.ca
COMMENTS:
Manitoba Hydro’s Comments on
Project 2010-07 Generator Requirements at the Transmission Interface
Informal Comment Period Open
March 4 – April 4, 2011
Comments:
Question: How can the proposal outlined in the White Paper be improved? Is the drafting team heading
in the right direction?
Response:
Manitoba Hydro (MH) does not agree with the SDT position that qualifying generator interconnection
facilities should be classified as part of the BES, but “That does not mean, however, that a Generator
Owner or Generator Operator should be required to automatically register as a Transmission Owner or
Transmission Operator simply because it owns and/or operates transmission Elements or Facilities”.
The premise for adding Generator Owner to the applicability section of FAC-001-0 appears to be based
on the presumed need to cover the situation where a generator owner receives a request to
interconnect to a line owned by the generator. MH disagrees that this is even a feasible scenario. If the
Generator is not a transmission owner or a transmission provider, what is the mechanism to implement
such a request? The generator would have to be a transmission provider and offer a transmission tariff.
All interconnection requests should be implemented by the Transmission Owner regardless if the
interconnection point is within a GO facility or end-user facility. The TO is in the best position to set
unbiased connection requirements to ensure the reliability of the BES is maintained. If a mechanism is
created to allow interconnection to a BES line owned by Generator, then it is essential for this Generator
providing this interconnection service to be a Transmission Owner to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is maintained.
MH does not understand the SDTs rationale for the statement “Requiring any classification that subjects
Generator Owners and Generator Operators to all the standards applicable to Transmission Owners and
Transmission Operators would do little, if anything, to improve the reliability of the Bulk Electric
System”. This statement is not consistent with the first sentence of the previous paragraph where the
SDT states “The SDT believes it is appropriate to classify various generating Facilities and Elements
(including generator interconnection facilities) as part of the Bulk Electric System”. If reliability is not
impacted, why is it appropriate to classify various Generating Facilities and Elements (including
generator interconnection facilities) as part of the BES? It is not logical to allow the Generator to be a
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“partial transmission owner”. If the Generator has transmission which is part of the BES, and over which
tariff service is provided, the Generator must be a Transmission owner. Consequently, there is no need
to change the applicability of FAC-001-0.
Question: The drafting team has chosen to use informal means of receiving industry feedback
(webinars, presentations before industry stakeholder groups, etc.) prior to expending valuable industry
resources to develop specific proposals for reliability standard requirements, measures, VSLs, etc. Do
you have any further suggestions for seeking industry input before the project moves into a more formal
development phase?
Response:
We believe that the industry resources would be better served by reviewing and responding to a specific
draft of a proposed standard rather than providing comments on a direction in which the SDT should
proceed. If there is uncertainty as to what needs to be included in the standard, we question the need
for the standard given the numerous other standard proposals in the NERC queue.
Question: The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility”
and “Generator Interconnection Operational Interface” as part of this project. The Project 2010-07
drafting team believes that changes to the definition of Bulk Electric System under Project 2010-17 and
modifications to a select group of standards can accomplish the same goal without the need for new
definitions. Do you support this approach? If not, please explain.
RESPONSE:
MANITOBA HYDRO SUPPORTS AN APPROACH WHICH RELIES ON THE DEFINITION OF THE BES,
INCLUDING ANY EXCLUSION AND INCLUSION CRITERIA, TO DETERMINE THE FACILITIES THAT SHOULD BE
PART OF THE BES. GIVEN THAT MANY GENERATORS ARE RADIAL CONNECTIONS TO THE BES, SPECIFIC
CRITERIA NEED TO BE DEVELOPED TO INCLUDE THESE CONNECTIONS IN THE BES.
Applicability of FAC-003-01
Comment:
Does the SDT have data to quantify the number of miles of transmission lines 100 kV and above that can
be attributed to “multiple generating units spread over several thousand acres”? Are these thousands of
acres within station fences where vegetation can be completely managed by the Generator? How many
vegetation contacts have been experienced on these generator interconnection lines? Vegetation
management is more of an issue for a Transmission Owner who has 10’s of thousands of miles of lines
and may not be able to inspect/maintain it all without a proper process. MH would recommend that
Generator Owner not be added to FAC-003-2. If NERC decides to go in this direction then we question if
radial lines connecting Load to the BES should be in the same category. Generator Owner’s may have
more underground cables than overhead lines and outages due to cable faults could be more frequent
than vegetation contact.
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May 18, 2011
Dan Roethemeyer, Dynegy
Dan.Roethemeyer@dynegy.com
COMMENTS:
Per the March 4, 2011 email regarding informal comments for Project 2010-07 Generator
Requirements at the Transmission Interface, I am submitting the following comments on behalf of
Dynegy Inc.:
· How can the proposal outlined in the White Paper be improved? Overall, the team has
done a good job isolating the possible additional Standards/Requirements to only those
which could impact reliability of the BES. However, with respect to FAC-003-2, there
should be exclusion criteria based on the length of the generator tie line since short tie
lines are commonly inspected as part of regular/routine inspections of generating plant
and/or substation facilities. As such, we suggest generator tie lines 1 mile in length or
shorter be excluded from FAC-003-2.
· How can the proposal outlined in the White Paper be improved? With respect to
inclusion in Standard FAC-001-0, Generators typically have no experience dealing with
Interconnection requests. As such, we suggest the team consider allowing the generator
45 days to first meet with an appropriate member of the BES (or other applicable expert)
to then subsequently develop the applicable documentation in R1, R2, R3 within an agreed
to time between the parties.
Thanks for your consideration.
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May 18, 2011
Dan Duff, Liberty Electric Power
610-872-7585
dduff@libgen.com
COMMENTS:
First, let me state that the team has done an outstanding job on this White Paper. I believe the
proposal will go a long way towards improving the reliability of the BES without imposing undue
hardships on GO/GOP registrants.
That being said, I do object to the removal of the “two span” language from the proposal. In my
particular circumstances (and I am sure I am not alone in this case) our interface is approximately
30 feet from our step-up transformer – measured horizontally, there is less than ten feet from
transformer to interface. To burden us with the entire vegetation management program serves no
reliability purpose, but does add a large paperwork burden. Restoring some kind of distance
requirement would remove those unnecessary burdens, and increase the chances of this worthy
effort being translated into an accepted standard.
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May 18, 2011
Gary Tarplee, Edison Mission Energy
714.513.8112
gtarplee@edisonmission.com
COMMENTS:
Thanks for the opportunity to provide comments on the White Paper.
EME is very supportive of the direction of the proposed White Paper. It is more efficient to
modify the existing Standards as compared to creating new Standards specifically for GO's and
GOP's. We offer the following comments;
1. It is imperative that the generation interconnection facilities and associated generation tie
lines are not required to register as a TO and TOP regardless of voltage or line length.
2. Generation interconnection tie lines should be identified as being outside the substation
fence and should be exempt if less than 0.25 miles in length.
3. The addition of the GO and GOP to IRO-005 may be redundant to TOP-001 R13. Please
review. If the TOP has responsibility for the generation interface the GO and GOP should
only have responsibility to inform the TOP when the GO's SPS or control equipment is
non-automatic or the GOP is not able to implement a TOP operating procedure due to
some event at the generating plant.
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May 18, 2011
John Hagen, Pacific Gas and Electric Company
415-973-7356
JHH4@pge.com
COMMENTS:
PG&E as both a Transmission Owner, Transmission Operator, Generator Owner and Generator
Operator supports the proposed changes in the white paper.
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May 18, 2011
Jonathan Appelbaum, The United Illuminating Company
jonathan.appelbaum@uinet.com
COMMENTS:
March 24, 2011.
The following comments are submitted by the United Illuminating Company regarding Project
2010-07: Generator Requirements at the Transmission Interface White Paper Proposal .
How can the proposal outlined in the White Paper be improved? Is the drafting team heading
in the right direction?
UI does not agree with the direction and prefers the Ad hoc Group’s approach to defining new terms.
There are two base facts that this White Paper does not address. First, the NERC Statement of
Registration Criteria establishes the criteria for identifying what entities are required to register for a
particular function; and second once registered for a function all requirements for that function apply.
The SDT is attempting to split the baby by stating a Generator Owner may own an integrated
transmission element but is not required to register as a Transmission Owner.
On page 3 of the White Paper the SDT writes:
‘The SDT believes it is appropriate to classify various generating Facilities and Elements (including
generator interconnection facilities) as part of the Bulk Electric System. The SDT also believes that
qualifying generator interconnection facilities should be classified as transmission. That does not mean,
however, that a Generator Owner or Generator Operator should be required to automatically register as
a Transmission Owner or Transmission Operator simply because it owns and/or operates transmission
Elements or Facilities. While qualifying Generator Owners and Generator Operators can be classified as
owning and operating electric transmission Elements and Facilities, these are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.”
In this paragraph the SDT states that the Generator Owner owns transmission elements. This
statement alone is sufficient to require registration per the NERC Statement of Registration Criteria. But
the SDT states that contrary to the Registration Statement those owners of these facilities need not
register as Transmission Owners. The SDT then argues that the facility is not part of the integrated bulk
power system without providing any technical justification for the term “integrated transmission
facility”. These facilities are impacting the reliability of the bulk power system and therefore are
integrated into its operation. The SDT has to explain why these elements are not integrated. The SDT
then states that because these transmission elements are not integrated into the bulk power system
that all reliability requirements should not apply. The SDT is creating rules without reference to prior
precedent and NERC activities.
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The difficulty lies in the lack of a functional entity identified for these tie-lines. The creation of the
functional entity would then allow the Reliability Standards to be applicable to those entities.
To demonstrate the inferiority of the White Paper and its approach let’s review PRC-004. The White
Paper states that PRC-004 requires no modification because it already is applicable to Generator
Owners. PRC-004 utilizes the terms “transmission Protection system” and “generator Protection
System” thereby differentiating between the two types of Protection Systems. R1 applies to
Transmission Owners and Distribution Providers and their transmission Protection system, while R2
applies to Generator Owners and their generator Protection Systems. A Generator Owner owning and
operating a transmission element will not be required to report on misoperations and corrective action
plans for misoperations of the transmission Protection System even though the transmission Protection
System misoperations will as effectively interrupt the generator as misoperations on the generator
Protection System.
The drafting team has chosen to use informal means of receiving industry feedback
(webinars, presentations before industry stakeholder groups, etc.) prior to expending valuable
industry resources to develop specific proposals for reliability standard requirements,
measures, VSLs, etc. Do you have any further suggestions for seeking industry input before
the project moves into a more formal development phase?
Include Regional Entity Compliance Manager’s to provide opinion on this approach.
I agree that the SDT needs to communicate and obtain support for its approach prior to developing
Standards. I imagine there are strong advocates for each approach, GOTO and the SDT approach.
The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility”
and “Generator Interconnection Operational Interface” as part of this project. The Project
2010-07 drafting team believes that changes to the definition of Bulk Electric System under
Project 2010-17 and modifications to a select group of standards can accomplish the same
goal without the need for new definitions. Do you support this approach? If not, please
explain.
No. Project 2010-17 will not resolve the problem. The new definition of BES will identify
those generator leads that are part of the BES. It will not resolve this issue because once those
lines are identified a Transmission Owner and Transmission Operator are required to be
assigned. The problem is in the Functional Model, the NERC Statement of Registration
Criteria and the requirement that all Reliability Requirements apply to a Registered Entity.
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May 18, 2011
Steve Alexanders PE, Central Lincoln
541-574-2064
salexanderson@cencoast.com
COMMENTS:
Please see http://www.ferc.gov/whats-new/comm-meet/2011/031711/E-4.pdf, page 30,
paragraph 47.
The FERC statement “ The Commission clarifies that it was not our intent to disrupt the
NERC Rules of Procedure or the Statement of Compliance Registry Criteria” does not
support the SDT’s statement “Follow the Project 2010-17—Definition of Bulk Electric
System and ensure that the responsibility for generator interconnecting line leads is
appropriately and clearly assigned to Generator Owners and Operators.” While I fail to see
how a redefinition of the BES could not affect the registry criteria that references it, I still
suggest including a revision to the registry criteria to assure that GO/GOPs with
interconnection facilities are not registered as TO/TOPs.
No affect on Central Lincoln, but we support the team’s intent and thought you should be
aware of yesterday’s ruling.
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May 18, 2011
LARRY RODRIGUEZ, Entegra Power Services
(813) 301-4952
lrodriguez@entegrapower.com
COMMENTS:
There is no question that the main focus of the Project 2010-07 SDT should be the
assurance that all GIF are appropriately covered by the Reliability Standards. However, I
would only ask that SDT members keep the following issues in mind to assure focusing on
true reliability instead of possibly diminishing reliability in specific cases with unnecessary
documentation and procedures:
1. Regarding FAC-001, many GIF are connected to the BES by very short lateral
interconnections off the BES. In many cases we are talking about ¼ mile or less;
sometimes only a few hundred feet. In these cases would there even be the physical
possibility of an interconnection? Even an SPS or possible reactive device would
surely be installed in the substation or switchyard on either side of the line.
Therefore, should the SDT consider some qualifiers limiting the application of the
FAC-001 requirements?
2. Regarding FAC-003, what if in the same ¼ mile or less mentioned above, the
situation is one in which there are no trees, but only scrub brush under those very
short interconnections. In addition, the corridor width is only 200ft. and the entire few
acres are visible from the plant making for near daily inspection. And, let us not
forget these entities have enormous incentives to absolutely assure no vegetation
growth into their lines. Should there be the possibility of documenting with pictures
such a situation while still providing a limited VMP appropriate to this situation?
3. Many of the GIF we are considering are IPPs whose purpose for existence is to
provide reliable, clean, and efficient energy to the marketplace. In the cases of these
generators with very short interconnections and very limited staff of
operator/maintenance specialists, has the SDT considered that we might actually be
“diverting” true reliability efforts like generating MW & MVAR and
communication/coordination with the RC, BA, and TOP by burdening them with an
unnecessary level of documentation/procedures commensurate with the actual
situation?
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May 18, 2011
Greg Froehling, Green Country Energy
(918)299-5689 x61
gfroehling@gcgen.com
COMMENTS:
• The Ad Hoc group originally proposed the new terms “Generator Interconnection Facility” and
“Generator Interconnection Operational Interface” as part of this project.
The Project 2010-07 drafting team believes that changes to the definition of Bulk Electric
System under Project 2010-17 and modifications to a select group of standards can accomplish
the same goal without the need for new definitions.
Do you support this approach?
No let me explain.
Proposed BES definition:
Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s)) with aggregate capacity greater than 75 MVA (gross
nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above.
(Looking for “Bright Lines” Leaves an unclear delineation at the GSU end and
Transmission facilities end. GSU needs to be addressed as Low and High sides,
Transmission Facilities does not identify a responsibility change.)
My Definition:
“Generator Interconnection Facility:
The Facilities from the high side of the Generation plant GSU operated at 100kV or above,
to the point of connection to Transmission Facilities that delineates a responsibility /
ownership change from Generator Owner to the Transmission Owner.”
( I see this as very bright lines for who is responsible for what)
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Ken Parker, Entegra Power Group, LLC
813-301-4907
kparker@entegrapower.com
COMMENTS:
FAC-001
Consideration should be given for FAC-001 applicability for Generator Owners
(registered entity) with ¼ to ½ mile of transmission interconnection to the BES,
serving no load, and without plans to solicit interconnection requests. It serves no
reliability purpose to burden those entities with FAC-001 R1, R2 and R3
requirements. Is it correct to assume R4 would only apply when an interconnection
request is received?
FAC-003-2
Consideration should be given for FAC-003-2 applicability for Generator Owners
(registered entity) with ¼ to ½ mile of transmission interconnection to the BES and
serving no load. For example, we have a ¼ mile interconnection that can be seen in
its entirety from the facility administration building, from which visual inspections
regularly take place. Does the SDT envision a simple one page TVMP when
circumstances are as described here?
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Mace Hunter, PE, Lakeland Electric
863-834-6516
Mace.Hunter@lakelandelectric.com
COMMENTS:
1. Add “Generator Owner” to the Applicability section of FAC-001-0 and add a requirement
and a measure to address the responsibilities specific to the Generator Owner.
FAC-001-0—Facility Connection Requirements currently applies to Transmission Owners and
addresses the need for Transmission Owners to establish facility connection and performance
requirements. While the standard requires Transmission Owners to address connection
requirements for “generation facilities, transmission facilities, and end-user facilities,” it does not
address the requirements for a Generator Owner that has received a request for interconnection.
The lack of such requirements for a Generator Owner’s Facility could result in gaps.
Therefore, the SDT proposes that “Generator Owner” be added to the Applicability section of
FAC-001-0. It further proposes the addition of Requirement 4 and a corresponding measure:
R4. Generator Owner that receives an interconnection request for its facility shall, within
45 days of such a request, be required to comply with requirements R1, R2, and R3 for the
facility for which it received the interconnection request.
M4. The Generator Owner that receives an interconnection request for its facility shall
make available (to its Compliance Monitor) for inspection evidence that it met the
requirements stated in Reliability Standard FAC-001-0 R4.
The way I read this proposal is that a GO has no obligation under FAC-001 until it receives an
interconnection request then it has 45 days to provide the requestor the elements listed in R1 and
R2. The GO should also have an obligation under R3 to maintain the facility connection
requirements that it provided to the requestor.
In most cases the GO will be requesting an interconnection with a TO. I think FAC-001 works fine in
this case. I also agree that a GO should comply with FAC-003 for longer generator leads between its
step up T/F and the interconnection with its TO. The question is how long do the leads have to be
before the FAC-003 standard becomes effective. Requiring a GO to have an VMP for a short line
with no vegetation issues seems extreme.
I don’t think a GO would want to lose a generator (lose $s) due
to a vegetation problem so he will have some type of program in place for a longer line.
Food for thought.
END OF SUMMARY
84
Informal Comments on White Paper for Project 2010-07—Generator Requirements at the
Transmission Interface
The Project 2010-07—Generator Requirements at the Transmission Interface standard drafting team
(drafting team) thanks all who provided comments during this stage of development. The White Paper
Proposal for Informal Comment was posted for a 30-day informal public comment period from March 4,
2011 through April 4, 2011. The stakeholders were asked to provide feedback via email to the NERC
Project Coordinator. 51 sets of comments were submitted.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
The SDT has completed the review of the informal comments from industry for Project 2010-07—
Generator Requirements at the Transmission Interface. Each comment was reviewed and considered by
the drafting team as it proposed modifications to FAC-001 and FAC-003 and developed the project’s
background document, and it will continue to consider this stakeholder feedback as the project
progresses. If a comment is not specifically addressed, it is likely because the drafting team has
addressed it elsewhere or the comment did not add clarity or otherwise improve the quality of the
proposed standards.
A majority of commenters supported the concepts in the white paper, which represent a focused but
comprehensive approach to including responsibility for generator interconnection Facilities in NERC’s
Reliability Standards. Most commenters agreed that the approach of developing specific changes to a
limited number of standards was preferable to developing new definitions or revising existing
definitions.
The drafting team received many comments on the general direction of the project:
•
•
•
Some suggested that an interim solution be implemented until the modified standards are
approved. The drafting team is providing input to NERC compliance staff upon request as it
works toward an interim solution.
Some said that Generator Owners and Generator Operators that are radial in nature should
not have to comply with any additional standards. In this phase of the project, the drafting
team’s goal was to identify and modify standards necessary to eliminate any reliability gaps
related to extended generation interconnection Facilities. Ultimately, this shall prevent the
registration of Generator Owners and Generator Operators as Transmission Owners and
Transmission Operators. After review of all of the standards, the drafting team believes that it is
appropriate to apply FAC-001 and FAC-003 to Generator Owners (in certain cases). This was
confirmed by stakeholder comments during the informal comment period.
Some were concerned with the drafting team’s use the term “transmission” to label generator
interconnection Facilities. Several commenters were concerned with the use of “transmission
lines” as a label for generator interconnection Facilities. While such a label has been applied in
other contexts by certain entities, the drafting team has avoided that labeling in its
modifications to FAC-001 and FAC-003 and its background documents.
•
•
•
•
Some were concerned that the white paper did not acknowledge interface agreements. The
drafting team recognizes that interface/interconnection agreements usually have explicit
language about coordination between Generator Owners and Operators and Transmission
Owners and Operators, but unfortunately these agreements are not viewed by regulatory
authorities as a tool that can be used for meeting reliability standards.
Some encouraged the SDT to revisit certain standards that already apply to Generator Owners
and Generator Operators because some standards split requirements by applicable entity. The
drafting team has reviewed the standards that already include Generator Owners and Generator
Operators and determined that no changes to specific requirements are necessary. The drafting
team attempted to better explain its rationale in these cases in the latest version of the
background document.
Several addressed commercial issues in their comments on the white paper. Such comments
are outside the scope of this drafting team (and NERC Reliability Standards in general) and thus
have not been addressed here.
Some pointed out reference errors in the white paper. The drafting team is grateful for these
comments and has attempted to remedy all errors in the resource document that has evolved
from the white paper.
The drafting team received no comments indicating that it should have included standards other than
the two identified (FAC-001 and FAC-003), but several commenters suggested modifications to the
proposed approaches to FAC-001 and FAC-003.
A number of comments stated that the “trigger” for the application of FAC-001 should not be the receipt
of a request, but rather should be based upon “the intent or obligation” to interconnect a new Facility to
an existing interconnecting Facility that is owned by a generator. Accordingly, the drafting team has
proposed language to address this concern. The intent of this modified language is to start the
compliance clock when the generator Facility owner executes an Agreement to perform the reliability
assessment required in FAC-002. This step should occur whether the generator voluntarily agrees to the
interconnection request or is compelled by a regulatory body to do so. In either case, we expect the
Generator Owner and the requestor to execute some form of an Agreement. The drafting team
intentionally excluded a specific reference to the kind of Agreement (such as a feasibility study) in
deference to comments that we should avoid comingling of commercial and reliability aspects in
reliability standards.
Similarly, a majority of comments supported FAC-003 applicability to the Generator Owner but
suggested some exclusion for a “short length” Facility. Accordingly, we modified the language to apply
only to a Facility that extends at least ½ mile beyond the fenced boundary(ies) of the switchyard,
generating station, or generating substation.
In addition to the majority of comments addressing the line length issue, the drafting team received
some minority comments on FAC-003:
•
•
•
•
Some indicated that Generator Owners should not be added to FAC-003 because they are
never an IROL circuit. FAC-003 addresses circuits other than those associated with an IROL.
Some stated that changing FAC-003 would do nothing to prevent adverse reliability impacts,
because a radial line can’t cascade. The drafting team believes there is a reliability-related need
to apply FAC-003 to GOs with extended interconnection Facilities.
One commenter suggested a better connection between FAC-003 and FAC-014, stating that
there is nothing in either standard where the Planning Coordinator is informing the
Transmission Owners and Generator Owners of the applicability of their Facilities as outlined
in the Facilities section 4.2.2 of FAC-003. FAC-014-2 R5 addresses this issue.
One commenter suggested that the requirement simply be that the Generator Owner
coordinates with the Transmission Owner to ensure that the generator interconnection
Facilities are included. The drafting team believes there is a reliability-related need to apply
FAC-003 to Generator Owners with extended interconnection Facilities. An entity always has the
opportunity to enter into a JRO where appropriate.
A majority of commenters also supported the drafting team’s proposal to not adopt new defined terms.
But many commenters said that if the new terms were not adopted, the drafting team needed to work
to address registration issues related to Generator Owners and Generator Operators, especially those
with ownership/operational responsibility for the Facility that interconnects the generator(s) to the
Transmission Owner’s Facility. A few stated that there needed to be a clearer delineation of
responsibilities between the Generator Owner and Transmission Owner and the Generator Operator
and Transmission Operator where ownership and operational responsibility of an interconnection
Facility wasn’t clearly understood. While the drafting team agrees with some of the comments, it is not
empowered to make all changes which may be necessary to alleviate the concerns expressed in the
comments.
However, during this process, the drafting team has been meeting with NERC and FERC staffs, regional
compliance managers, and industry organizations to discuss possible solutions to the issue of concern to
most Generator Owner/Generator Operators (e.g., registration as a Transmission Owner/Transmission
Operator). The drafting team believes this issue, and the related concerns, have the attention of
appropriate NERC and regional staffs and has volunteered to provide assistance in their efforts to
address them.
The goal of the Project 2010-07 drafting team is to work with NERC and regional compliance
enforcement and compliance registration staffs to develop a comprehensive package that will address
all reliability gaps, whether real or perceived, so that entities are appropriately registered and the
appropriate reliability standards are applied to those entities.
**Note about comments from February and March 2010 SAR Posting**
During its review of these comments, the drafting team also returned to comments from its SAR posting
in February and March of 2010, as many of the comments on the SAR posting dealt with the proposals in
the original Ad Hoc Group for Generator Requirements at the Transmission Interface’s Final Report. In
returning to these comments, the drafting team confirmed that it had addressed all relevant comments.
Because of the narrower focus of the current Project 2010-07, many comments (such as those on the Ad
Hoc Group’s proposed definitions) were no longer relevant, but all others have been addressed:
•
•
•
•
Need to align project with compliance responsibility: The drafting team is working with NERC
and regional compliance staffs on exactly this.
The scope of the project is too broad: The scope has been narrowed.
The project needs further clarification: The original white paper posted for informal comment
was developed to provide further clarification on the project. That white paper has been
modified to be used as a background resource document.
The standards changes should be implemented all at once: With only two standard changes
being implemented and an interim solution being developed by NERC’s compliance staff (in
coordination with Regional compliance staff), the drafting team is not as concerned with
implementing the changes simultaneously. If, for instance, FAC-001 changes are implemented
before FAC-003 changes, the interim compliance solution will remain in effect until FAC-003
changes are also implemented to ensure that there are no gaps during the implementation
periods.
The drafting team thanks all those who participated in the original SAR posting; the comments from that
posting were invaluable during the transition from ad hoc group to standard drafting team.
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A.
Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose: To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1.
Transmission Owner
4.2.
Applicable Generator Owner
2.4.1.
5.
B.
The drafting team limited its
modifications to those associated
with expanding the scope to
include the Generator Owner and
bringing the format up to date.
Generator Owner with an executed Agreement to evaluate the reliability
impact of interconnecting another Facility to its existing generation Facility
Effective Date:
5.1.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner
and Regional Entity become effective upon Board of Trustees’ adoption.
5.2.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required,
all requirements applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter one year after Board of Trustees’ adoption.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner, within 45 days of executing an Agreement to evaluate the
reliability impact of interconnecting another Facility to its existing generation Facility (under
FAC-002-1), shall document and publish and thereafter maintain Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements.
[VRF – Medium]
Draft 1: June 17, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
R3. Each applicable Generator Owner with Facility connection requirements and each
Transmission Owner shall have Facility connection requirements that address the
following items:
3.1. Provide a written summary of its plans to achieve the required system
performance as described in Requirements R1 and R2 throughout the planning
horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts
on the interconnected Transmission Systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission Systems)
as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System Protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. Each applicable Generator Owner with Facility connection requirements (in accordance with
Requirement R2) and each Transmission Owner shall maintain Facility connection
requirements and make documentation of these requirements available to the users of the
Transmission System, the Regional Entity, and ERO on request (five business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 1: June 17, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that executes an Agreement to evaluate the reliability impact of
interconnecting another Facility to its existing generation Facility shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each applicable Generator Owner with Facility connection requirements and each
Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all requirements stated in Requirement R3.
M4. Each applicable Generator Owner with Facility connection requirements and each
Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 1: June 17, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R#
R1
Lower VSL
Not Applicable.
Moderate VSL
High VSL
The Transmission
Owner failed to do
one of the
following:
The Transmission
Owner failed to do
one of the
following:
Document or
maintain or publish
Facility connection
requirements as
specified in the
Requirement
Document or
maintain or publish
its Facility
connection
requirements as
specified in the
Requirement
Severe VSL
The Transmission
Owner did not
develop Facility
connection
requirements.
OR
OR
Failed to include
one (1) of the
components and
specified in R1.1,
R1.2 or R1.3.
Failed to include
(2) of the
components as
specified in R1.1,
R1.2 or R1.3
OR
R2
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 45
calendar days but
less than or equal
to 60 calendar days
Draft 1: June 17, 2011
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 60
calendar days but
less than or equal
to 70 calendar days
4 of 6
Failed to document
or maintain or
publish its Facility
connection
requirements as
specified in the
Requirement and
failed to include
one (1) of the
components as
specified in R1.1,
R1.2 or R1.3.
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 70
calendar days but
less than or equal
to 80 calendar days
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 80 days
after executing an
Agreement to
evaluate the
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
R3
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
The responsible
entity’s Facility
connection
requirements failed
to address one of
the
subrequirements.
The responsible
entity’s Facility
connection
requirements failed
to address two of
the
subrequirements.
The responsible
entity’s Facility
connection
requirements failed
to address three of
the subrequirements.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the
subrequirements.
OR
R4
E.
The responsible
entity made the
requirements
available more than
five business days
but less than or
equal to 10
business days after
a request.
The responsible
entity made the
requirements
available more than
10 business days
but less than or
equal to 20
business days after
a request.
The responsible
entity made the
requirements
available more than
20 business days
less than or equal
to 30 business days
after a request.
The responsible
entity does not
have Facility
connection
requirements.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date
Revision under Project
2010-07
Draft 1: June 17, 2011
5 of 6
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Draft 1: June 17, 2011
6 of 6
S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
A.
Introduction
The drafting team limited its
modifications to those associated
with expanding the scope to
include the Generator Owner and
bringing the format up to date.
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 1
3.
Purpose: To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Ffacility connection and performance requirements.
4.
Applicability:
4.1.
Transmission Owner
4.2.
Applicable Generator Owner
4.1.2.4.1.
Generator Owner with an executed Agreement to evaluate the reliability
impact of interconnecting another Facility to its existing generation Facility
5.
Effective Date:
5.1.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner
and Regional Entity become effective upon Board of Trustees’ adoption.
5.2.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required,
all requirements applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter one year after Board of Trustees’ adoption.
5.
B.
April 1, 2005
Requirements
R1. The Transmission Owner shall document, maintain, and publish Ffacility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability OrganizationEntity, subregional, Power Pool, and individual Transmission Owner
planning criteria and Ffacility connection requirements. The Transmission Owner’s Ffacility
connection requirements shall address connection requirements for:
1.1.
Generation Ffacilities,
1.2.
Transmission Ffacilities, and
R2.
End-user Ffacilities
1.3.
[VRF – Medium]
R2. Each applicable Generator Owner, within 45 days of executing an Agreement to evaluate the
reliability impact of interconnecting another Facility to its existing generation Facility (under
FAC-002-1), shall document and publish and thereafter maintain Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements.
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
1 of 6
S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
R3. [VRF – Medium]
R3. Each applicable Generator Owner with Facility connection requirements and each The
Transmission Owner shall have Facility connection requirements that address the
following items:
3.1. Provide a written summary of its plans to achieve the required system
performance as described above in Requirements R1 and R2 throughout the
planning horizon:
3.1.1. Procedures for coordinated joint studies of new Ffacilities and their
impacts on the interconnected Ttransmission Ssystems.
3.1.2. Procedures for notification of new or modified Ffacilities to others (those
responsible for the reliability of the interconnected tTransmission
Ssystems) as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System pProtection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Ffacilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Ffacilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. Each applicable Generator Owner with Facility connection requirements (in accordance with
Requirement R2) and eachThe Transmission Owner shall maintain and update its Ffacility
connection requirements as required and. The Transmission Owner shall make documentation
of these requirements available to the users of the Ttransmission Ssystem, the Regional
Reliability OrganizationEntity, and NERC ERO on request (five business days).
R4. [VRF – Medium]
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance MonitorEnforcement
Authority) for inspection evidence that it met all the requirements stated in Reliability
Standard FAC-001-0_Requirement R1.
M2. Each Generator Owner that executes an Agreement to evaluate the reliability impact of
interconnecting another Facility to its existing generation Facility shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M2.M3. Each applicable Generator Owner with Facility connection requirements and eachThe
Transmission Owner shall make available (to its Compliance MonitorEnforcement Authority)
for inspection evidence that it met all requirements stated in Reliability Standard FAC-0010_Requirement R32.
M3.M4. Each applicable Generator Owner with Facility connection requirements and eachThe
Transmission Owner shall make available (to its Compliance MonitorEnforcement Authority)
for inspection evidence that it met all the requirements stated in Reliability Standard FAC001-0_Requirement R43.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
Compliance Monitor: Regional Reliability Organization.Entity
1.2.
Compliance Monitoring Period and Reset Timeframe
On request (five business days).
1.2.
Data RetentionCompliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation:
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
• The Generator Owner shall retain evidence of Requirement R2, Measure M2,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
1.3.
None specified.
1.4.
Additional Compliance Information
None.
2.
Levels of Non-ComplianceViolation Severity Levels
R#
R1
Lower VSL
Not Applicable.
Moderate VSL
High VSL
The Transmission
Owner failed to do
one of the
following:
The Transmission
Owner failed to do
one of the
following:
Document or
maintain or publish
Facility connection
requirements as
specified in the
Requirement
Document or
maintain or publish
its Facility
connection
requirements as
specified in the
Requirement
Severe VSL
The Transmission
Owner did not
develop Facility
connection
requirements.
OR
OR
Failed to include
one (1) of the
components and
specified in R1.1,
R1.2 or R1.3.
Failed to include
(2) of the
components as
specified in R1.1,
R1.2 or R1.3
OR
Failed to document
or maintain or
publish its Facility
connection
requirements as
specified in the
Requirement and
failed to include
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
4 of 6
S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
R2
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 45
calendar days but
less than or equal
to 60 calendar days
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 60
calendar days but
less than or equal
to 70 calendar days
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
one (1) of the
components as
specified in R1.1,
R1.2 or R1.3.
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 70
calendar days but
less than or equal
to 80 calendar days
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
R3
The responsible
entity’s Facility
connection
requirements failed
to address one of
the
subrequirements.
The responsible
entity’s Facility
connection
requirements failed
to address two of
the
subrequirements.
The responsible
entity’s Facility
connection
requirements failed
to address three of
the subrequirements.
The responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 80 days
after executing an
Agreement to
evaluate the
reliability impact
of interconnecting
another Facility to
its existing
generation Facility.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the
subrequirements.
OR
R4
The responsible
entity made the
requirements
available more than
five business days
but less than or
equal to 10
business days after
a request.
The responsible
entity made the
requirements
available more than
10 business days
but less than or
equal to 20
business days after
a request.
The responsible
entity made the
requirements
available more than
20 business days
less than or equal
to 30 business days
after a request.
The responsible
entity does not
have Facility
connection
requirements.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
2.
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
5 of 6
S ta n d a rd FAC-001-0 1 — Fa c ility Co n n e c tio n Re q u ire m e nts
E.
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date
Revision under Project
2010-07
Adopted by NERC Board of Trustees: February 8, 2005Draft 1: June 17, 2011
Effective Date: April 1, 2005
6 of 6
Implementation Plan for FAC-001-1 – Facility Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-001-0 will be retired when FAC-001-1 becomes effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from
those in the FERC-approved version of the standard, the expectation is that Transmission
Owners will maintain their current state of compliance. Thus, the standard is effective for
Transmission Owners upon approval, as detailed below.
The proposed changes to the FERC-approved version of this standard only address
Generator Owner applicability and requirements (add Generator Owner to section 4.2,
introduce a new requirement (R2), and modify two existing requirements (now R3 and
R4)). Therefore, this implementation plan only identifies a compliance timeframe for
Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner and Regional Entity become effective upon Board of
Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Generator Owner become effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities. In those jurisdictions where no regulatory
approval is required, all requirements applied to the Generator Owner become
effective on the first calendar day of the first calendar quarter one year after Board
of Trustees’ adoption.
1
FAC-003-3 — Transmission Vegetation Management
S ta n d a rd De ve lo p m e n t Tim e lin e
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Forth draft of revised standard posted (June 17, 2010-July 17, 2010).
Proposed Action Plan and Description of Current Draft
This is the third posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the fifth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Anticipated Date
January 2011
Receive BOT approval
February 2011
Draft 6: June 17, 2011
1
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner
become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The third effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for is
required. In those jurisdictions where no regulatory approval is required, Requirements R1,
R2, R4, R5, R6, and R7 become effective on the first day of the first calendar quarter two
years following Board of Trustees adoption.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
Draft 6: June 17, 2011
2
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
3
April 4, 2007
May 16, 2011
Draft 6: June 17, 2011
Regulatory Approval — Effective Date
Modified proposed definitions and
Applicability to include Generator
Owners of a certain length.
New
Revision under Project
2010-07
3
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’scontrol
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
Draft 6: June 17, 2011
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
4
FAC-003-3 — Transmission Vegetation Management
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project
will be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has develop two sets of proposed changes: one to this version, the latest draft of
Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired once FAC003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection
Facility in the standard with as few other changes as possible.
In tro d u c tio n
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Objectives:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1. Functional Entities:
4.1.1. Applicable Transmission Owners
4.1.1.1.
Transmission Owners that own Transmission Facilities defined in 4.2
4.1.2. Applicable Generator Owners
4.1.2.1.
Generator Owners that own Generation Facilities defined in 4.3
Draft 6: June 17, 2011
5
FAC-003-3 — Transmission Vegetation Management
4.2. Transmission Facilities: Defined below (referred to as “applicable lines”), including
but not limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
Rationale
4.2.1.
Overhead transmission lines
operated at 200kV or higher.
4.2.2.
Overhead transmission lines
operated below 200kV having been
identified as included in the
definition of an Interconnection
Reliability Operating Limit (IROL)
under NERC Standard FAC-014
by the Planning Coordinator.
4.2.3.
Overhead transmission lines
operated below 200 kV having
been identified as included in the
definition of one of the Major
WECC Transfer Paths in the Bulk
Electric System.
4.2.4.
This standard applies to overhead transmission lines identified above (4.2.1
through 4.2.3) located outside the fenced area of the switchyard, station or
substation and any portion of the span of the transmission line that is crossing
the substation fence.
The areas excluded in 4.2.4 were excluded based on
comments from industry for reasons summarized as
follows: 1) There is a very low risk from vegetation
in this area. Based on an informal survey, no TOs
reported such an event. 2) Substations, switchyards,
and stations have many inspection and maintenance
activities that are necessary for reliability. Those
existing process manage the threat. As such, the
formal steps in this standard are not well suited for
this environment. 3) Specifically addressing the
areas where the standard applies or doesn’t makes
the standard stronger as it relates to clarity.
4.3. Generation Facilities: Defined below (referred to as
“applicable lines”):
4.3.1. Overhead transmission lines that extend greater
than one half mile beyond the fenced area of the
switchyard, generating station or generating
substation up to the point of interconnection with the
Transmission system and are:
4.3.1.1.
Operated at 200kV or higher; or
Within the text of
NERC Reliability
Standard FAC-003-3,
“transmission line(s)”
and “applicable line(s)”
can also refer to the
generation Facilities as
referenced in 4.3 and its
subsections.
4.3.1.2.
Operated below 200kV having been identified as included in the definition
of an Interconnection Reliability Operating Limit (IROL) under NERC
Standard FAC-014 by the Planning Coordinator; or
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 6: June 17, 2011
6
FAC-003-3 — Transmission Vegetation Management
4.3.1.3.
Operated below 200kV having been identified as included in the definition
of one of the Major WECC Transfer Paths in the Bulk Electric System.
4.4. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard. [Straw proposal]
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Right-of-Way, vandalism, human activities and acts of nature. Operating
experience indicates that trees that have grown out of specification have contributed to
Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
Draft 6: June 17, 2011
7
FAC-003-3 — Transmission Vegetation Management
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 6: June 17, 2011
8
FAC-003-3 — Transmission Vegetation Management
Re q u ire m e n ts a n d Me a s u re s
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of an applicable Transmission
Owner’s or applicable Generator Owner’s
vegetation maintenance program since the
encroachments listed require different and
increasing levels of skills and knowledge
and thus constitute a logical progression of
how well, or poorly, an applicable
Transmission Owner or applicable
Generator Owner manages vegetation
relative to this Requirement.
R1. Each applicable Transmission Owner and
applicable Generator Owner shall manage
vegetation to prevent encroachments of the
types shown below, into the Minimum
Vegetation Clearance Distance (MVCD) of
any of its applicable line(s) identified as an
element of an Interconnection Reliability
Operating Limit (IROL) in the planning
horizon by the Planning Coordinator; or Major
Western Electricity Coordinating Council
(WECC) transfer path(s); operating within its
Rating and all Rated Electrical Operating
Conditions. 2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the Right-of-Way (ROW) that
caused a vegetation-related Sustained
Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in
R1. Examples of acceptable forms of evidence may include dated attestations, dated
reports containing no Sustained Outages associated with encroachment types 2
through 4 above, or records confirming no Real-time observations of any MVCD
encroachments.
If a later confirmation of a Fault by the applicable Transmission Owner or applicable
Generator Owner shows that a vegetation encroachment within the MVCD has
occurred from vegetation within the ROW, this shall be considered the equivalent of a
Real-time observation.
2
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, arboricultural activities or
horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this footnote should be
construed to limit the applicable Transmission Owner’s or applicable Generator Owner ’s right to exercise its full
legal rights on the ROW.
Draft 6: June 17, 2011
9
FAC-003-3 — Transmission Vegetation Management
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
R2. Each applicable Transmission Owner and
applicable Generator Owner shall manage
vegetation to prevent encroachments of the
types shown below, into the MVCD of any of
its applicable line(s) that is not an element of
an IROL; or Major WECC transfer path;
operating within its Rating and all Rated
Electrical Operating Conditions.2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the ROW that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that
caused a vegetation-related Sustained
Outage.
[VRF – Medium] [Time Horizon – Realtime]
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of an applicable Transmission
Owner’s or applicable Generator Owner’s
vegetation maintenance program since the
encroachments listed require different and
increasing levels of skills and knowledge
and thus constitute a logical progression of
how well, or poorly, an applicable
Transmission Owner or applicable
Generator Owner manages vegetation
relative to this Requirement.
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in
R2. Examples of acceptable forms of evidence may include dated attestations, dated
reports containing no Sustained Outages associated with encroachment types 2
through 4 above, or records confirming no Real-time observations of any MVCD
encroachments.
If a later confirmation of a Fault by the applicable Transmission Owner and
applicable Generator Owner shows that a vegetation encroachment within the MVCD
has occurred from vegetation within the ROW, this shall be considered the equivalent
of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
Draft 6: June 17, 2011
10
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner and
applicable Generator Owner shall have
documented maintenance strategies or
procedures or processes or specifications it
uses to prevent the encroachment of
vegetation into the MVCD of its applicable
transmission lines that include(s) the
following:
3.1 Accounts for the movement of
applicable transmission line conductors
under their Facility Rating and all Rated
Electrical Operating Conditions;
3.2 Accounts for the inter-relationships
between vegetation growth rates,
vegetation control methods, and
inspection frequency.
Rationale
The documentation provides a basis for
evaluating the competency of the applicable
Transmission Owner’s or applicable
Generator Owner’s ’s vegetation program.
There may be many acceptable approaches
to maintain clearances. Any approach must
demonstrate that the applicable
Transmission Owner or applicable
Generator Owner avoids vegetation-to-wire
conflicts under all Rated Electrical
Operating Conditions. See Figure 1 for an
illustration of possible conductor locations.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner and
Rationale
applicable Generator Owner, without any
To ensure expeditious communication between
intentional time delay, shall notify the
the applicable Transmission Owner or
control center holding switching authority
applicable Generator Owner and the control
for the associated applicable transmission
center when a critical situation is confirmed.
line when the applicable Transmission
Owner or applicable Generator Owner has
confirmed the existence of a vegetation condition that is likely to cause a Fault at any
moment.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 6: June 17, 2011
11
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner or
applicable Generator Owner is constrained
from performing vegetation work, and the
constraint may lead to a vegetation
encroachment into the MVCD of its
applicable transmission lines prior to the
implementation of the next annual work plan
then the applicable Transmission Owner or
applicable Generator Owner shall take
corrective action to ensure continued
vegetation management to prevent
encroachments.
[VRF – Medium] [Time Horizon – Operations
Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work. In cases where the transmission line
is put at potential risk due to constraints, the
intent is for the applicable Transmission
Owner or applicable Generator Owner to
put interim measures in place, rather than do
nothing. The corrective action process is
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence
of the corrective action taken for each constraint where an applicable transmission
line was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, and evidence that a line was de-energized. (R5)
R6. Each applicable Transmission Owner and
applicable Generator Owner shall
perform a Vegetation Inspection of 100%
of its applicable transmission lines
(measured in units of choice - circuit,
pole line, line miles or kilometers, etc.) at
least once per calendar year and with no
more than 18 months between
inspections on the same ROW. 3
[VRF – Medium] [Time Horizon –
Operations Planning]
M6. Each applicable Transmission
Owner and applicable Generator
Rationale
Inspections are used by applicable Transmission
Owners and applicable Generator Owners to
assess the condition of the entire ROW. The
information from the assessment can be used to
determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar year
but with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America and
on common utility practice, this minimum
frequency is reasonable. Applicable
Transmission Owners and applicable Generator
Owners should consider local and environmental
factors that could warrant more frequent
inspections.
3
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the applicable Transmission Owner or
applicable Generator Owner is granted a time extension that is equivalent to the duration of the time the applicable
Transmission Owner or applicable Generator Owner was prevented from performing the Vegetation Inspection.
Draft 6: June 17, 2011
12
FAC-003-3 — Transmission Vegetation Management
Owner has evidence that it conducted Vegetation Inspections of the transmission line
ROW for all applicable transmission lines at least once per calendar year but with no
more than 18 months between inspections on the same ROW. Examples of acceptable
forms of evidence may include completed and dated work orders, dated invoices, or
dated inspection records. (R6)
R7. Each applicable Transmission Owner and
Rationale
applicable Generator Owner shall complete
This requirement sets the expectation that
100% of its annual vegetation work plan to
the work identified in the annual work plan
ensure no vegetation encroachments occur
will be completed as planned. An annual
within the MVCD. Modifications to the work
vegetation work plan allows for work to be
plan in response to changing conditions or to
modified for changing conditions, taking
findings from vegetation inspections may be
into consideration anticipated growth of
made (provided they do not put the
vegetation and all other environmental
transmission system at risk of a vegetation
factors, provided that the changes do not
encroachment) and must be documented. The
violate the encroachment within the MVCD.
percent completed calculation is based on the
number of units actually completed divided by
the number of units in the final amended plan (measured in units of choice - circuit, pole
line, line miles or kilometers, etc.) Examples of reasons for modification to annual plan
may include:
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 4
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
• Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence that
it completed its annual vegetation work plan. Examples of acceptable forms of evidence may
include a copy of the completed annual work plan (including modifications if any), dated work
orders, dated invoices, or dated inspection records. (R7)
4
Circumstances that are beyond the control of a applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, major
storms as defined either by the applicable Transmission Owner or applicable Generator Owner or an applicable
regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
Draft 6: June 17, 2011
13
FAC-003-3 — Transmission Vegetation Management
Co m p lia n c e
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The applicable Transmission Owner and applicable Generator Owner retains data or
evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7, Measures M1,
M2, M3, M5, M6 and M7 for three calendar years unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of an
investigation.
The applicable Transmission Owner and applicable Generator Owner retains data or
evidence to show compliance with Requirement R4, Measure M4 for most recent 12 months
of operator logs or most recent 3 months of voice recordings or transcripts of voice
recordings, unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable Transmission Owner or applicable Generator Owner is found non-compliant,
it shall keep information related to the non-compliance until found compliant or for the time
period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable Generator
Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s
designee, identifying all Sustained Outages of applicable transmission lines determined by
the applicable Transmission Owner or applicable Generator Owner to have been caused by
vegetation, except as excluded in footnote 2, which includes as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the applicable Transmission Owner or applicable Generator Owner .
A Sustained Outage is to be categorized as one of the following:
Draft 6: June 17, 2011
14
FAC-003-3 — Transmission Vegetation Management
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
o Category 4B — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
The Regional Entity will report the outage information provided by applicable Transmission
Owners and applicable Generator Owners, as per the above, quarterly to NERC, as well as
any actions taken by the Regional Entity as a result of any of the reported Sustained Outages.
Draft 6: June 17, 2011
15
FAC-003-3 — Transmission Vegetation Management
Tim e Ho rizo n s , Vio la tio n Ris k Fa c to rs , a n d Vio la tio n S e ve rity Le ve ls
Table 1
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
Violation Severity Level
Lower
Moderate
High
The responsible entity had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The responsible entity had an
encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
High
The
responsible
entity had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The responsible entity had an
encroachment into the MVCD due to a
fall-in from inside the ROW that
caused a vegetation-related Sustained
Outage.
The responsible entity had an
encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
Medium
The
responsible
entity had an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The responsible entity has maintenance
strategies or documented procedures or
processes or specifications but has not
accounted for the inter-relationships
between vegetation growth rates,
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for the
The responsible entity does not
have any maintenance strategies
or documented procedures or
processes or specifications used
to prevent the encroachment of
Lower
Draft 6: June 17, 2011
16
Severe
FAC-003-3 — Transmission Vegetation Management
vegetation control methods, and
inspection frequency, for the
responsible entity’s applicable lines.
R4
R5
R6
Real-time
Operations
Planning
Operations
Planning
Medium
movement of transmission
line conductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
responsible entity’s
applicable lines.
vegetation into the MVCD, for
the responsible entity’s
applicable lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
transmission line, but there
was intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center holding
switching authority for that
transmission line.
The responsible entity did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
Draft 6: June 17, 2011
The
responsible
entity failed to
inspect 5% or
less of its
applicable
transmission
lines
(measured in
units of
choice circuit, pole
line, line
miles or
The responsible entity failed to inspect
more than 5% up to and including 10%
of its applicable transmission lines
(measured in units of choice - circuit,
pole line, line miles or kilometers,
etc.).
The responsible entity failed
to inspect more than 10% up
to and including 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
17
The responsible entity failed to
inspect more than 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
kilometers, etc.).
FAC-003-3 — Transmission Vegetation Management
kilometers,
etc.)
R7
Operations
Planning
Medium
Draft 6: June 17, 2011
The
responsible
entity failed to
complete up
to 5% of its
annual
vegetation
work plan
(including
modifications
if any).
The responsible entity failed to
complete more than 5% and up to 10%
of its annual vegetation work plan
(including modifications if any).
The responsible entity failed
to complete more than 10%
and up to 15% of its annual
vegetation work plan
(including modifications if
any).
18
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan
(including modifications if any).
FAC-003-3 — Transmission Vegetation Management
Va ria n c e s
None.
In te rp re ta tio n s
None.
Draft 6: June 17, 2011
19
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each applicable Transmission Owner and applicable
Generator Owner to manage vegetation to prevent encroachment within the Minimum Vegetation
Clearance Distance (“MVCD”) of transmission lines. R1 is applicable to lines “identified as an
element of an Interconnection Reliability Operating Limit (IROL) or Major Western Electricity
Coordinating Council (WECC) transfer path (operating within Rating and Rated Electrical
Operating Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that
are not an element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related
encroachment resulting in a Sustained Outage due to blowing together of applicable lines and
vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of a Fault by an applicable Transmission Owner or
applicable Generator Owner confirms that a vegetation encroachment within the MVCD
occurred, then it shall be considered the equivalent of a Real-time observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of an applicable Transmission Owner and applicable Generator Owner to manage
vegetation and to the corresponding performance level of the applicable Transmission Owner’s
or applicable Generator Owner’s vegetation program’s ability to meet the goal of “preventing a
Sustained Outage that could lead to Cascading.” Thus violation severity increases with an
Draft 6: June 17, 2011
20
FAC-003-3 — Transmission Vegetation Management
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb may only partially break and intermittently contact a conductor. Such events are
considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Facilities. Keeping
vegetation from entering this space will prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, an applicable Transmission Owner or applicable
Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the
Transmission System. The approach provides the basis for evaluating the intent, allocation of
appropriate resources and the competency of the applicable Transmission Owner or applicable
Generator Owner in managing vegetation. There are many acceptable approaches to manage
vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to state what its approach is and how it conducts work
to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Draft 6: June 17, 2011
21
FAC-003-3 — Transmission Vegetation Management
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner’s or applicable Generator Owner’s employee who
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
Draft 6: June 17, 2011
22
FAC-003-3 — Transmission Vegetation Management
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until the vegetation threat is relieved. Appropriate
actions may include a temporary reduction in the line loading, switching the line out of service,
or positioning the system in recognition of the increasing risk of outage on that circuit. The
notification of the threat should be communicated in terms of minutes or hours as opposed to a
longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Sustained Outage risk
when temporarily constrained from performing vegetation maintenance. The intent of this
requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing vegetation
maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or
applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
Draft 6: June 17, 2011
23
FAC-003-3 — Transmission Vegetation Management
•
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates an
applicable Transmission Owner’s or applicable Generator Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent inspections are needed to maintain reliability levels, dependent
upon such factors as anticipated growth rates of the local vegetation, length of the growing
season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is
expected that some transmission lines may be designated with a higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the applicable
Transmission Owner or applicable Generator Owner may choose units such as: line miles or
kilometers, circuit miles or kilometers, pole line miles, ROW miles, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of 230 kV transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it
was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or
5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to implement an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
Draft 6: June 17, 2011
24
FAC-003-3 — Transmission Vegetation Management
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan. Modifications to the annual work plan must always ensure the
reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management in the long term because it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Draft 6: June 17, 2011
25
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)
5
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
5
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially
greater distances will be achieved at time of vegetation maintenance.
Draft 6: June 17, 2011
26
FAC-003-3 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
Draft 6: June 17, 2011
27
FAC-003-3 — Transmission Vegetation Management
•
•
•
avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
transmission lines operate in non-laboratory environments (wet conditions)
transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would
have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of
an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are
usually 1.5 per unit or less.
Draft 6: June 17, 2011
28
FAC-003-3 — Transmission Vegetation Management
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is
considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1].
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 6: June 17, 2011
29
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
Table 5
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
8.89
5.65
3.52
3.35
1.6
IEEE 516
MAID (ft)
@ Alt. 3000 feet
8.65
4.92
3.13
2.8
1.4
Table 5
(historical maximums)
Draft 6: June 17, 2011
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.0
2.4
3.0
3.0
3.0
14.36
11.0
8.55
5.28
2.46
IEEE 516
MAID (ft)
@ Alt. 3000 feet
13.95
10.07
7.47
4.2
2.1
30
FAC-003-3 — Transmission Vegetation Management
Table 7
Draft 6: June 17, 2011
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
31
FAC-003-2 3 — Transmission Vegetation Management
S ta n d a rd De ve lo p m e n t Tim e lin e
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Forth draft of revised standard posted (June 17, 2010-July 17, 2010).
Proposed Action Plan and Description of Current Draft
This is the third posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the fifth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Anticipated Date
January 2011
Receive BOT approval
February 2011
Draft 65: January 27, 2011June 17, 2011
1
FAC-003-2 3 — Transmission Vegetation Management
Effe c tive Da te s
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner
become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The third effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for is
required. In those jurisdictions where no regulatory approval is required, Requirements R1,
R2, R4, R5, R6, and R7 become effective on the first day of the first calendar quarter two
years following Board of Trustees adoption.
First calendar day of the first calendar quarter one year after the date of the order approving
the standard from applicable regulatory authorities where such explicit approval is required.
Exceptions:
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
Draft 65: January 27, 2011June 17, 2011
2
FAC-003-2 3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
23
April 4, 2007
May 16, 2011
Regulatory Approval — Effective Date
Modified proposed definitions and
Applicability to include Generator
Owners of a certain length.
Draft 65: January 27, 2011June 17, 2011
New
Revision under Project
2010-07
3
FAC-003-23 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary. When this standard has received ballot approval, the text
boxes will be moved to the Guideline and Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator
Owner’sTransmission Owner’s control that are
likely to pose a hazard to the line(s) prior to the next
planned maintenance or inspection. This may be
combined with a general line inspection.
Draft 6 5: December 17, 2010June 17, 2011
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
4
FAC-003-23 — Transmission Vegetation Management
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project
will be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has develop two sets of proposed changes: one to this version, the latest draft of
Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired once FAC003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection
Facility in the standard with as few other changes as possible.
In tro d u c tio n
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-32
3. Objectives:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1. Functional Entities:
4.1.1. Applicable Transmission Owners
4.1.1.1.
Transmission Owners that own Transmission Facilities defined in 4.2
4.1.2. Applicable Generator Owners
4.1.2.1.
Generator Owners that own Generation Facilities defined in 4.3
4.1. Functional Entities:
Transmission Owners
Draft 6 5: December 17, 2010June 17, 2011
5
FAC-003-23 — Transmission Vegetation Management
4.2. Transmission Facilities: Defined below (referred to as “applicable lines”), including
but not limited to those that cross lands owned by federal 1, state, provincial, public,
private, or tribal entities:
Rationale
4.2.1.
Overhead transmission lines
operated at 200kV or higher.
4.2.2.
Overhead transmission lines
operated below 200kV having been
identified as included in the
definition of an Interconnection
Reliability Operating Limit (IROL)
under NERC Standard FAC-014
by the Planning Coordinator.
4.2.3.
Overhead transmission lines
operated below 200 kV having
been identified as included in the
definition of one of the Major
WECC Transfer Paths in the Bulk
Electric System.
4.2.4.
This standard applies to overhead transmission lines identified above (4.2.1
through 4.2.3) located outside the fenced area of the switchyard, station or
substation and any portion of the span of the transmission line that is crossing
the substation fence.
-The areas excluded in 4.2.4 were excluded based
on comments from industry for reasons summarized
as follows: 1) There is a very low risk from
vegetation in this area. Based on an informal
survey, no TOs reported such an event. 2)
Substations, switchyards, and stations have many
inspection and maintenance activities that are
necessary for reliability. Those existing process
manage the threat. As such, the formal steps in this
standard are not well suited for this environment. 3)
The standard was written for Transmission Owners.
Rolling the excluded areas into this standard will
bring GO and DP into the standard, even though
NERC has an initiative in place to address this
bigger registry issue. 43) Specifically addressing
the areas where the standard applies or doesn’t
makes the standard stronger as it relates to clarity.
4.3. Generation Facilities: Defined below (referred to as
“applicable lines”):
4.3.1. Overhead transmission lines that extend greater
than one half mile beyond the fenced area of the
switchyard, generating station or generating
substation up to the point of interconnection with the
Transmission system and are:
4.3.1.1.
Operated at 200kV or higher; or
Within the text of
NERC Reliability
Standard FAC-003-3,
“transmission line(s)”
and “applicable line(s)”
can also refer to the
generation Facilities as
referenced in 4.3 and its
subsections.
4.3.1.2.
Operated below 200kV having been identified as included in the definition
of an Interconnection Reliability Operating Limit (IROL) under NERC
Standard FAC-014 by the Planning Coordinator; or
1
EPAct 2005 section 1211c: “Access approvals by Federal agencies”.
Draft 6 5: December 17, 2010June 17, 2011
6
FAC-003-23 — Transmission Vegetation Management
4.3.1.3.
Operated below 200kV having been identified as included in the definition
of one of the Major WECC Transfer Paths in the Bulk Electric System.
4.3. Enforcement: The reliability obligations of the applicable entities and facilities are
contained within the technical requirements of this standard. [Straw proposal]
4.4.
5. Background:
This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth
approach to improve the reliability of the electric Transmission System by preventing those
vegetation related outages that could lead to Cascading. This Standard is not intended to
address non-preventable outages such as those due to vegetation fall-ins or blow-ins from
outside the Right-of-Way, vandalism, human activities and acts of nature. Operating
experience indicates that trees that have grown out of specification have contributed to
Cascading, especially under heavy electrical loading conditions.
With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide
layers of protection to prevent vegetation related outages that could lead to Cascading:
a)
Performance-based — defines a particular reliability objective or outcome to be
achieved.
b)
Risk-based — preventive requirements to reduce the risks of failure to acceptable
tolerance levels.
c)
Competency-based — defines a minimum capability an entity needs to have to
demonstrate it is able to perform its designated reliability functions.
The defense-in-depth strategy for reliability standards development recognizes that each
requirement in a NERC reliability standard has a role in preventing system failures, and that
these roles are complementary and reinforcing. Reliability standards should not be viewed as
a body of unrelated requirements, but rather should be viewed as part of a portfolio of
requirements designed to achieve an overall defense-in-depth strategy and comport with the
quality objectives of a reliability standard. For this Standard, the requirements have been
developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
Thus the various requirements associated with a successful vegetation program could be
viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or
Draft 6 5: December 17, 2010June 17, 2011
7
FAC-003-23 — Transmission Vegetation Management
final level of defense. R6 depending on the particular vegetation approach may be either an
initial defense barrier or a final defense barrier.
Major outages and operational problems have resulted from interference between overgrown
vegetation and transmission lines located on many types of lands and ownership situations.
Adherence to the Standard requirements for applicable lines on any kind of land or easement,
whether they are Federal Lands, state or provincial lands, public or private lands, franchises,
easements or lands owned in fee, will reduce and manage this risk. For the purpose of the
Standard the term “public lands” includes municipal lands, village lands, city lands, and a
host of other governmental entities.
This Standard addresses vegetation management along applicable overhead lines and does
not apply to underground lines, submarine lines or to line sections inside an electric station
boundary.
This Standard focuses on transmission lines to prevent those vegetation related outages that
could lead to Cascading. It is not intended to prevent customer outages due to tree contact
with lower voltage distribution system lines. For example, localized customer service might
be disrupted if vegetation were to make contact with a 69kV transmission line supplying
power to a 12kV distribution station. However, this Standard is not written to address such
isolated situations which have little impact on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses an
increased outage risk, especially when numerous transmission lines are operating at or near
their Rating. This can present a significant risk of multiple line failures and Cascading.
Conversely, most other outage causes (such as trees falling into lines, lightning, animals,
motor vehicles, etc.) are statistically intermittent. These events are not any more likely to
occur during heavy system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such events. Therefore
these types of events are highly unlikely to cause large-scale grid failures. Thus, this
Standard’s emphasis is on vegetation grow-ins.
Draft 6 5: December 17, 2010June 17, 2011
8
FAC-003-23 — Transmission Vegetation Management
Re q u ire m e n ts a n d Me a s u re s
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of an applicable Transmission
Owner’s or applicable Generator Owner’s a
TO’s vegetation maintenance program since
the encroachments listed require different
and increasing levels of skills and
knowledge and thus constitute a logical
progression of how well, or poorly, an
applicable Transmission Owner or
applicable Generator Owner a TO manages
vegetation relative to this Requirement.
R1. Each applicable Transmission Owner and
applicable Generator Owner Transmission
Owner shall manage vegetation to prevent
encroachments of the types shown below, into
the Minimum Vegetation Clearance Distance
(MVCD) of any of its applicable line(s)
identified as an element of an Interconnection
Reliability Operating Limit (IROL) in the
planning horizon by the Planning Coordinator;
or Major Western Electricity Coordinating
Council (WECC) transfer path(s); operating
within its Rating and all Rated Electrical
Operating Conditions. 2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the Right-of-Way (ROW) that
caused a vegetation-related Sustained
Outage,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,
4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.
[VRF – High] [Time Horizon – Real-time]
M1. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it managed vegetation to prevent encroachment into the
MVCD as described in R1. Examples of acceptable forms of evidence may include
dated attestations, dated reports containing no Sustained Outages associated with
encroachment types 2 through 4 above, or records confirming no Real-time
observations of any MVCD encroachments.
If a later confirmation of a Fault by the applicable Transmission Owner or applicable
Generator Owner Transmission Owner shows that a vegetation encroachment within
the MVCD has occurred from vegetation within the ROW, this shall be considered
the equivalent of a Real-time observation.
2
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner Transmission Owner subject to this reliability standard, including natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by
the applicable Transmission Owner or applicable Generator Owner Transmission Owner or an applicable regulatory
body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with
tree, arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing
in this footnote should be construed to limit the applicable Transmission Owner’s or applicable Generator Owner
Transmission Owner’s right to exercise its full legal rights on the ROW.
Draft 6 5: December 17, 2010June 17, 2011
9
FAC-003-23 — Transmission Vegetation Management
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R1)
R2. Each applicable Transmission Owner and
applicable Generator Owner Transmission
Owner shall manage vegetation to prevent
encroachments of the types shown below, into
the MVCD of any of its applicable line(s) that
is not an element of an IROL; or Major WECC
transfer path; operating within its Rating and
all Rated Electrical Operating Conditions.2
1. An encroachment into the MVCD as
shown in FAC-003-Table 2, observed in
Real-time, absent a Sustained Outage,
2. An encroachment due to a fall-in from
inside the ROW that caused a vegetationrelated Sustained Outage,
3. An encroachment due to blowing together
of applicable lines and vegetation located
inside the ROW that caused a vegetationrelated Sustained Outage,
4. An encroachment due to a grow-in that
caused a vegetation-related Sustained
Outage.
[VRF – Medium] [Time Horizon – Realtime]
Rationale
The MVCD is a calculated minimum
distance stated in feet (meters) to prevent
flash-over between conductors and
vegetation, for various altitudes and
operating voltages. The distances in Table 2
were derived using a proven transmission
design method. The types of failure to
manage vegetation are listed in order of
increasing degrees of severity in noncompliant performance as it relates to a
failure of an applicable Transmission
Owner’s or applicable Generator Owner’s
TO’s vegetation maintenance program
since the encroachments listed require
different and increasing levels of skills and
knowledge and thus constitute a logical
progression of how well, or poorly, an
applicable Transmission Owner or
applicable Generator Owner TO manages
vegetation relative to this Requirement.
M2. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it managed vegetation to prevent encroachment into the
MVCD as described in R2. Examples of acceptable forms of evidence may include
dated attestations, dated reports containing no Sustained Outages associated with
encroachment types 2 through 4 above, or records confirming no Real-time
observations of any MVCD encroachments.
If a later confirmation of a Fault by the applicable Transmission Owner and
applicable Generator Owner Transmission Owner shows that a vegetation
encroachment within the MVCD has occurred from vegetation within the ROW, this
shall be considered the equivalent of a Real-time observation.
Multiple Sustained Outages on an individual line, if caused by the same vegetation,
will be reported as one outage regardless of the actual number of outages within a 24hour period. (R2)
Draft 6 5: December 17, 2010June 17, 2011
10
FAC-003-23 — Transmission Vegetation Management
R3. Each applicable Transmission Owner and
applicable Generator Owner Transmission
Owner shall have documented maintenance
strategies or procedures or processes or
specifications it uses to prevent the
encroachment of vegetation into the MVCD
of its applicable transmission lines that
include(s) the following:
3.1 Accounts for the movement of
applicable transmission line conductors
under their Facility Rating and all Rated
Electrical Operating Conditions;
3.2 Accounts for the inter-relationships
between vegetation growth rates,
vegetation control methods, and
inspection frequency.
Rationale
The documentation provides a basis for
evaluating the competency of the applicable
Transmission Owner’s or applicable
Generator Owner’s Transmission Owner’s
vegetation program. There may be many
acceptable approaches to maintain
clearances. Any approach must
demonstrate that the applicable
Transmission Owner or applicable
Generator Owner Transmission Owner
avoids vegetation-to-wire conflicts under all
Rated Electrical Operating Conditions. See
Figure 1 for an illustration of possible
conductor locations.
[VRF – Lower] [Time Horizon – Long Term Planning]
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
Transmission Owner can prevent encroachment into the MVCD considering the
factors identified in the requirement. (R3)
R4. Each applicable Transmission Owner and
Rationale
applicable Generator OwnerTransmission
To ensure expeditious communication between
Owner, without any intentional time delay,
the applicable Transmission Owner or
shall notify the control center holding
applicable Generator Owner Transmission
switching authority for the associated
Owner and the control center when a critical
applicable transmission line when the
situation is confirmed.
applicable Transmission Owner or
applicable Generator Owner Transmission Owner has confirmed the existence of a
vegetation condition that is likely to cause a Fault at any moment.
[VRF – Medium] [Time Horizon – Real-time]
M4. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner that has a confirmed vegetation condition likely to cause a Fault at any
moment will have evidence that it notified the control center holding switching
authority for the associated transmission line without any intentional time delay.
Examples of evidence may include control center logs, voice recordings, switching
orders, clearance orders and subsequent work orders. (R4)
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11
FAC-003-23 — Transmission Vegetation Management
R5. When a applicable Transmission Owner or
applicable Generator Owner Transmission
Owner is constrained from performing
vegetation work, and the constraint may lead
to a vegetation encroachment into the MVCD
of its applicable transmission lines prior to the
implementation of the next annual work plan
then the applicable Transmission Owner or
applicable Generator Owner Transmission
Owner shall take corrective action to ensure
continued vegetation management to prevent
encroachments.
[VRF – Medium] [Time Horizon – Operations
Planning]
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner Transmission
Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner or
applicable Generator Owner Transmission
Owner to put interim measures in place,
rather than do nothing.
The corrective action process is intended to
address situations where a planned work
methodology cannot be performed but an
alternate work methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence of the corrective action taken for each constraint where an
applicable transmission line was put at potential risk. Examples of acceptable forms
of evidence may include initially-planned work orders, documentation of constraints
from landowners, court orders, inspection records of increased monitoring,
documentation of the de-rating of lines, revised work orders, invoices, and evidence
that a line was de-energized. (R5)
Rationale
Inspections are used by applicable Transmission
Owners and applicable Generator Owners
Transmission Owners to assess the condition of
the entire ROW. The information from the
R6. Each applicable Transmission Owner and
assessment can be used to determine risk,
applicable Generator Owner
determine future work and evaluate recentlyTransmission Owner shall perform a
completed work. This requirement sets a
Vegetation Inspection of 100% of its
minimum Vegetation Inspection frequency of
applicable transmission lines (measured
once per calendar year but with no more than 18
in units of choice - circuit, pole line, line
months between inspections on the same ROW.
miles or kilometers, etc.) at least once
Based upon average growth rates across North
per calendar year and with no more than
America and on common utility practice, this
18 months between inspections on the
3
minimum frequency is reasonable. Applicable
same ROW.
Transmission Owners and applicable Generator
Owners Transmission Owners should consider
[VRF – Medium] [Time Horizon –
local and environmental factors that could
Operations Planning]
warrant more frequent inspections.
3
When the applicable Transmission Owner or applicable Generator Owner Transmission Owner is prevented from
performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the applicable Transmission
Owner or applicable Generator Owner TO is granted a time extension that is equivalent to the duration of the time
the applicable Transmission Owner or applicable Generator Owner TO was prevented from performing the
Vegetation Inspection.
Draft 6 5: December 17, 2010June 17, 2011
12
FAC-003-23 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it conducted Vegetation Inspections of the transmission line
ROW for all applicable transmission lines at least once per calendar year but with no
more than 18 months between inspections on the same ROW. Examples of acceptable
forms of evidence may include completed and dated work orders, dated invoices, or
dated inspection records. (R6)
R7. Each applicable Transmission Owner and
Rationale
applicable Generator Owner Transmission
This requirement sets the expectation that
Owner shall complete 100% of its annual
the work identified in the annual work plan
vegetation work plan to ensure no vegetation
will be completed as planned. An annual
encroachments occur within the MVCD.
vegetation work plan allows for work to be
Modifications to the work plan in response to
modified for changing conditions, taking
changing conditions or to findings from
into consideration anticipated growth of
vegetation inspections may be made (provided
vegetation and all other environmental
they do not put the transmission system at risk
factors, provided that the changes do not
of a vegetation encroachment) and must be
violate the encroachment within the MVCD.
documented. The percent completed
calculation is based on the number of units
actually completed divided by the number of units in the final amended plan (measured in
units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for
modification to annual plan may include:
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner Transmission Owner 4
• Rescheduling work between growing seasons
• Crew or contractor availability/ Mutual assistance agreements
• Identified unanticipated high priority work
• Weather conditions/Accessibility
• Permitting delays
• Land ownership changes/Change in land use by the landowner
• Emerging technologies
[VRF – Medium] [Time Horizon – Operations Planning]
M7. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it completed its annual vegetation work plan. Examples of acceptable
forms of evidence may include a copy of the completed annual work plan (including
modifications if any), dated work orders, dated invoices, or dated inspection records. (R7)
4
Circumstances that are beyond the control of a applicable Transmission Owner or applicable Generator Owner
Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes,
landslides, major storms as defined either by the applicable Transmission Owner or applicable Generator Owner TO
or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.
Draft 6 5: December 17, 2010June 17, 2011
13
FAC-003-23 — Transmission Vegetation Management
Co m p lia n c e
Compliance Enforcement Authority
•
Regional Entity
Compliance Monitoring and Enforcement Processes:
•
•
•
•
•
•
•
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
Periodic Data Submittals
Evidence Retention
The applicable Transmission Owner and applicable Generator Owner Transmission Owner
retains data or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time as
part of an investigation.
The applicable Transmission Owner and applicable Generator Owner Transmission Owner
retains data or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or transcripts
of voice recordings, unless directed by its Compliance Enforcement Authority to retain
specific evidence for a longer period of time as part of an investigation.
If an applicable Transmission Owner or applicable Generator Owner Transmission Owner is
found non-compliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all requested
and submitted subsequent audit records.
Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable Generator
Owner Transmission Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable transmission lines
determined by the applicable Transmission Owner or applicable Generator Owner
Transmission Owner to have been caused by vegetation, except as excluded in footnote 2,
which includes as a minimum, the following:
o The name of the circuit(s), the date, time and duration of the outage; the voltage
of the circuit; a description of the cause of the outage; the category associated
with the Sustained Outage; other pertinent comments; and any countermeasures
taken by the applicable Transmission Owner or applicable Generator Owner
Transmission Owner.
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14
FAC-003-23 — Transmission Vegetation Management
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, that are identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into
applicable transmission lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines that are identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
o Category 4B — Blowing together: Sustained Outages caused by vegetation and
applicable transmission lines, but are not identified as an element of an IROL or
Major WECC Transfer Path, blowing together from within the ROW.
The Regional Entity will report the outage information provided by applicable Transmission
Owners and applicable Generator OwnersTransmission Owners, as per the above, quarterly
to NERC, as well as any actions taken by the Regional Entity as a result of any of the
reported Sustained Outages.
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15
FAC-003-23 — Transmission Vegetation Management
Tim e Ho rizo n s , Vio la tio n Ris k Fa c to rs , a n d Vio la tio n S e ve rity Le ve ls
Table 1
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
Moderate
High
The Transmission Ownerresponsible
entity had an encroachment into the
MVCD due to a fall-in from inside the
ROW that caused a vegetation-related
Sustained Outage.
The Transmission
Ownerresponsible entity had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission
Ownerresponsible entity had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
High
The
Transmission
Ownerrespons
ible entity had
an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The
Transmission
Ownerrespons
ible entity had
an
encroachment
into the
MVCD
observed in
Real-time,
absent a
Sustained
Outage.
The Transmission Ownerresponsible
entity had an encroachment into the
MVCD due to a fall-in from inside the
ROW that caused a vegetation-related
Sustained Outage.
The Transmission
Ownerresponsible entity had
an encroachment into the
MVCD due to blowing
together of applicable lines
and vegetation located inside
the ROW that caused a
vegetation-related Sustained
Outage.
The Transmission
Ownerresponsible entity had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The Transmission Ownerresponsible
The Transmission
The Transmission
R2
Real-time
Medium
R3
Long-Term
Lower
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16
Severe
FAC-003-23 — Transmission Vegetation Management
Planning
R4
R5
R6
Real-time
Operations
Planning
Operations
Planning
entity has maintenance strategies or
documented procedures or processes or
specifications but has not accounted for
the inter-relationships between
vegetation growth rates, vegetation
control methods, and inspection
frequency, for the Transmission
Ownerresponsible entity’s applicable
lines.
Medium
Ownerresponsible entity has
maintenance strategies or
documented procedures or
processes or specifications
but has not accounted for the
movement of transmission
line conductors under their
Rating and all Rated
Electrical Operating
Conditions, for the
Transmission
Ownerresponsible entity’s
applicable lines.
Ownerresponsible entity does not
have any maintenance strategies
or documented procedures or
processes or specifications used
to prevent the encroachment of
vegetation into the MVCD, for
the Transmission
Ownerresponsible entity’s
applicable lines.
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
transmission line, but there
was intentional delay in that
notification.
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and did not
notify the control center holding
switching authority for that
transmission line.
The Transmission
Ownerresponsible entity did not
take corrective action when it
was constrained from performing
planned vegetation work where a
transmission line was put at
potential risk.
Medium
Medium
The
Transmission
Ownerrespons
ible entity
failed to
inspect 5% or
The Transmission Ownerresponsible
entity failed to inspect more than 5%
up to and including 10% of its
applicable transmission lines
(measured in units of choice - circuit,
pole line, line miles or kilometers,
Draft 6 5: December 17, 2010June 17, 2011
The Transmission
Ownerresponsible entity
failed to inspect more than
10% up to and including 15%
of its applicable transmission
lines (measured in units of
17
The Transmission
Ownerresponsible entity failed to
inspect more than 15% of its
applicable transmission lines
(measured in units of choice circuit, pole line, line miles or
FAC-003-23 — Transmission Vegetation Management
R7
Operations
Planning
Medium
less of its
applicable
transmission
lines
(measured in
units of
choice circuit, pole
line, line
miles or
kilometers,
etc.)
etc.).
choice - circuit, pole line, line
miles or kilometers, etc.).
kilometers, etc.).
The
Transmission
Ownerrespons
ible entity
failed to
complete up
to 5% of its
annual
vegetation
work plan
(including
modifications
if any).
The Transmission Ownerresponsible
entity failed to complete more than 5%
and up to 10% of its annual vegetation
work plan (including modifications if
any).
The Transmission
Ownerresponsible entity
failed to complete more than
10% and up to 15% of its
annual vegetation work plan
(including modifications if
any).
The Transmission
Ownerresponsible entity failed to
complete more than 15% of its
annual vegetation work plan
(including modifications if any).
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18
FAC-003-23 — Transmission Vegetation Management
Va ria n c e s
None.
In te rp re ta tio n s
None.
Draft 6 5: December 17, 2010June 17, 2011
19
FAC-003-23 — Transmission Vegetation Management
Guideline and Technical Basis
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the prevention of vegetation encroachments within a minimum distance of
transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to
different Facilities. Both R1 and R2 require each Transmission applicable Transmission Owner
and applicable Generator Owner Owner to manage vegetation to prevent encroachment within the
Minimum Vegetation Clearance Distance (“MVCD”) of transmission lines. R1 is applicable to
lines “identified as an element of an Interconnection Reliability Operating Limit (IROL) or Major
Western Electricity Coordinating Council (WECC) transfer path (operating within Rating and
Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2 applies to all other
applicable lines that are not an element of an IROL or Major WECC Transfer Path.
The separation of applicability (between R1 and R2) recognizes that an encroachment into the
MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the
electric transmission system. Applicable lines that are not an element of an IROL or Major
WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less
operationally significant. As a reflection of this difference in risk impact, the Violation Risk
Factors (VRFs) are assigned as High for R1 and Medium for R2.
These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table
1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-0032 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances
necessary to prevent spark-over based on the Gallet equations as described more fully in
Appendix 1 below.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating
(potentially in violation of other standards), the occurrence of a clearance encroachment may
occur. For example, emergency actions taken by a Transmission Operator or Reliability
Coordinator to protect an Interconnection may cause the transmission line to sag more and come
closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a
violation of these requirements.
Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation
encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment
resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related
encroachment resulting in a Sustained Outage due to blowing together of applicable lines and
vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained
Outage due to a grow-in. If an investigation of a Fault by an Transmission applicable
Transmission Owner or applicable Generator OwnerOwner confirms that a vegetation
encroachment within the MVCD occurred, then it shall be considered the equivalent of a Realtime observation.
With this approach, the VSLs were defined such that they directly correlate to the severity of a
failure of an Transmission applicable Transmission Owner and applicable Generator Owner
Owner to manage vegetation and to the corresponding performance level of the Transmission
applicable Transmission Owner’s or applicable Generator Owner’s Owner’s vegetation
Draft 6 5: December 17, 2010June 17, 2011
20
FAC-003-23 — Transmission Vegetation Management
program’s ability to meet the goal of “preventing a Sustained Outage that could lead to
Cascading.” Thus violation severity increases with an Transmission Own applicable
Transmission Owner’s or applicable Generator Owner’s er’s inability to meet this goal and its
potential of leading to a Cascading event. The additional benefits of such a combination are that
it simplifies the standard and clearly defines performance for compliance. A performance-based
requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example, a limb may only partially break and intermittently contact a conductor. Such events are
considered to be a single vegetation-related Sustained Outage under the Standard where the
Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
Requirement R3:
Requirement R3 is a competency based requirement concerned with the maintenance strategies,
procedures, processes, or specifications, an Transmission applicable Transmission Owner or
applicable Generator Owner Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
Transmission applicable Transmission Owner or applicable Generator Owner Owner uses to plan
and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the
Transmission System. The approach provides the basis for evaluating the intent, allocation of
appropriate resources and the competency of the Transmission applicable Transmission Owner
or applicable Generator Owner Owner in managing vegetation. There are many acceptable
approaches to manage vegetation and avoid Sustained Outages. However, the Transmission
applicable Transmission Owner or applicable Generator Owner Owner must be able to state what
its approach is and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
Transmission applicable Transmission Owner or applicable Generator Owner Owner chooses to
use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the Transmission applicable Transmission Owner or
applicable Generator Owner Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing as a reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
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21
FAC-003-23 — Transmission Vegetation Management
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below.
Figure 1
Cross-section view of a single conductor at a given point along the span showing six possible
conductor positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the
Transmission applicable Transmission Owner or applicable Generator Owner Owner for the
mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of
potentially threatening vegetation conditions, without any intentional delay, to the control center
holding switching authority for that specific transmission line. Examples of acceptable
unintentional delays may include communication system problems (for example, cellular service
or two-way radio disabled), crews located in remote field locations with no communication
access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an Transmission applicable Transmission Owner’s or applicable Generator Owner’s
Owner’s employee who personally identifies such a threat in the field. Confirmation could also
be made by sending out an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment
of the possible sag or movement of the conductor while operating between no-load conditions
and its rating.
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22
FAC-003-23 — Transmission Vegetation Management
The Transmission applicable Transmission Owner or applicable Generator Owner Owner has the
responsibility to ensure the proper communication between field personnel and the control center
to allow the control center to take the appropriate action until the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or positioning the system in recognition of the increasing risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some Transmission applicable Transmission Owners or applicable
Generator Owners Owners may have a danger tree identification program that identifies trees for
removal with the potential to fall near the line. These trees would not require notification to the
control center unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
Transmission applicable Transmission Owner or applicable Generator Owner Owner for the
mitigation of Sustained Outage risk when temporarily constrained from performing vegetation
maintenance. The intent of this requirement is to deal with situations that prevent the
Transmission applicable Transmission Owner or applicable Generator Owner Owner from
performing planned vegetation management work and, as a result, have the potential to put the
transmission line at risk. Constraints to performing vegetation maintenance work as planned
could result from legal injunctions filed by property owners, the discovery of easement
stipulations which limit the Transmission applicable Transmission Owner’s or applicable
Generator Owner’s Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
Transmission applicable Transmission Owner or applicable Generator Owner Owner is not under
any immediate time constraint for achieving the management objective, can easily reschedule
work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the Transmission applicable Transmission Owner or applicable Generator Owner Owner is
required to take an interim corrective action to mitigate the potential risk to the transmission line.
A wide range of actions can be taken to address various situations. General considerations
include:
•
•
•
Identifying locations where the Transmission applicable Transmission Owner or
applicable Generator Owner Owner is constrained from performing planned
vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for each location.
Draft 6 5: December 17, 2010June 17, 2011
23
FAC-003-23 — Transmission Vegetation Management
•
•
In developing the specific action to mitigate the potential risk to the transmission line
the Transmission applicable Transmission Owner or applicable Generator Owner
Owner could consider location specific measures such as modifying the inspection
and/or maintenance intervals. Where a legal constraint would not allow any
vegetation work, the interim corrective action could include limiting the loading on
the transmission line.
The Transmission applicable Transmission Owner or applicable Generator Owner
Owner should document and track the specific corrective action taken at each
location. This location may be indicated as one span, one tree or a combination of
spans on one property where the constraint is considered to be temporary.
•
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation
Inspections can be performed in conjunction with general line inspections further facilitates an
Transmission applicable Transmission Owner’s or applicable Generator Owner’s Owner’s ability
to meet this requirement. However, the Transmission applicable Transmission Owner or
applicable Generator Owner Owner may determine that more frequent inspections are needed to
maintain reliability levels, dependent upon such factors as anticipated growth rates of the local
vegetation, length of the growing season for the geographical area, limited ROW width, and
rainfall amounts. Therefore it is expected that some transmission lines may be designated with a
higher frequency of inspections.
The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW
inspections completed. To calculate the percentage of inspection completion, the Transmission
applicable Transmission Owner or applicable Generator Owner Owner may choose units such as:
line miles or kilometers, circuit miles or kilometers, pole line miles, ROW miles, etc.
For example, when an Transmission applicable Transmission Owner or applicable Generator
Owner Owner operates 2,000 miles of 230 kV transmission lines this Transmission applicable
Transmission Owner or applicable Generator Owner Owner will be responsible for inspecting all
2,000 miles of 230 kV transmission lines at least once during the calendar year. If one of the
included lines was 100 miles long, and if it was not inspected during the year, then the amount
failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this
example.
Requirement R7:
R7 is a risk-based requirement. The Transmission applicable Transmission Owner or applicable
Generator Owner Owner is required to implement an annual work plan for vegetation
management to accomplish the purpose of this standard. Modifications to the work plan in
response to changing conditions or to findings from vegetation inspections may be made and
Draft 6 5: December 17, 2010June 17, 2011
24
FAC-003-23 — Transmission Vegetation Management
documented provided they do not put the transmission system at risk. The annual work plan
requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line”
detailed description of all work to be performed. It is only intended to require that the
Transmission applicable Transmission Owner or applicable Generator Owner Owner provide
evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
The ability to modify the work plan allows the Transmission applicable Transmission Owner or
applicable Generator Owner Owner to change priorities or treatment methodologies during the
year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application
ineffective during the plan year, or a major storm could require redirecting local resources away
from planned maintenance. This situation may also include complying with mutual assistance
agreements by moving resources off the Transmission applicable Transmission Owner’s or
applicable Generator Owner’s Owner’s system to work on another system. Any of these
examples could result in acceptable deferrals or additions to the annual work plan. Modifications
to the annual work plan must always ensure the reliability of the electric Transmission system.
In general, the vegetation management maintenance approach should use the full extent of the
Transmission applicable Transmission Owner’s or applicable Generator Owner’s Owner’s
easement, fee simple and other legal rights allowed. A comprehensive approach that exercises
the full extent of legal rights on the ROW is superior to incremental management in the long
term because it reduces the overall potential for encroachments, and it ensures that future
planned work and future planned inspection cycles are sufficient.
When developing the annual work plan the Transmission applicable Transmission Owner or
applicable Generator Owner Owner should allow time for procedural requirements to obtain
permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start
dates. Transmission Applicable Transmission Owners or applicable Generator Owners Owners
may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator OwnerTransmission Owner, evidence of successful
annual work plan execution could consist of signed-off work orders, signed contracts, printouts
from work management systems, spreadsheets of planned versus completed work, timesheets,
work inspection reports, or paid invoices. Other evidence may include photographs, and walkthrough reports.
Draft 6 5: December 17, 2010June 17, 2011
25
FAC-003-23 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD)
5
For Alternating Current Voltages
( AC )
Nominal
System
Voltage
(kV)
( AC )
Maximum
System
Voltage
(kV)
765
800
500
550
345
362
230
242
161*
169
138*
145
115*
121
88*
100
69*
72
MVCD
feet
(meters)
sea level
8.06ft
(2.46m)
5.06ft
(1.54m)
3.12ft
(0.95m)
2.97ft
(0.91m)
2ft
(0.61m)
1.7ft
(0.52m)
1.41ft
(0.43m)
1.15ft
(0.35m)
0.82ft
(0.25m)
MVCD
feet
(meters)
3,000ft
(914.4m)
MVCD
feet
(meters)
4,000ft
(1219.2m)
MVCD
feet
(meters)
5,000ft
(1524m)
MVCD
feet
(meters)
6,000ft
(1828.8m)
8.89ft
(2.71m)
5.66ft
(1.73m)
3.53ft
(1.08m)
3.36ft
(1.02m)
2.28ft
(0.69m)
1.94ft
(0.59m)
1.61ft
(0.49m)
1.32ft
(0.40m)
0.94ft
(0.29m)
9.17ft
(2.80m)
5.86ft
(1.79m)
3.67ft
(1.12m)
3.49ft
(1.06m)
2.38ft
(0.73m)
2.03ft
(0.62m)
1.68ft
(0.51m)
1.38ft
(0.42m)
0.99ft
(0.30m)
9.45ft
(2.88m)
6.07ft
(1.85m)
3.82ft
(1.16m)
3.63ft
(1.11m)
2.48ft
(0.76m)
2.12ft
(0.65m)
1.75ft
(0.53m)
1.44ft
(0.44m)
1.03ft
(0.31m)
9.73ft
(2.97m)
6.28ft
(1.91m)
3.97ft
(1.21m)
3.78ft
(1.15m)
2.58ft
(0.79m)
2.21ft
(0.67m)
1.83ft
(0.56m)
1.5ft
(0.46m)
1.08ft
(0.33m)
MVCD
feet
(meters)
7,000ft
(2133.6m)
MVCD
feet
(meters)
8,000ft
(2438.4m)
MVCD
feet
(meters)
9,000ft
(2743.2m)
MVCD
feet
(meters)
10,000ft
(3048m)
MVCD
feet
(meters)
11,000ft
(3352.8m)
10.01ft
(3.05m)
6.49ft
(1.98m)
4.12ft
(1.26m)
3.92ft
(1.19m)
2.69ft
(0.82m)
2.3ft
(0.70m)
1.91ft
(0.58m)
1.57ft
(0.48m)
1.13ft
(0.34m)
10.29ft
(3.14m)
6.7ft
(2.04m)
4.27ft
(1.30m)
4.07ft
(1.24m)
2.8ft
(0.85m)
2.4ft
(0.73m)
1.99ft
(0.61m)
1.64ft
(0.50m)
1.18ft
(0.36m)
10.57ft
(3.22m)
6.92ft
(2.11m)
4.43ft
(1.35m)
4.22ft
(1.29m)
2.91ft
(0.89m)
2.49ft
(0.76m)
2.07ft
(0.63m)
1.71ft
(0.52m)
1.23ft
(0.37m)
10.85ft
(3.31m)
7.13ft
(2.17m)
4.58ft
(1.40m)
4.37ft
(1.33m)
3.03ft
(0.92m)
2.59ft
(0.79m)
2.16ft
(0.66m)
1.78ft
(0.54m)
1.28ft
(0.39m)
11.13ft
(3.39m)
7.35ft
(2.24m)
4.74ft
(1.44m)
4.53ft
(1.38m)
3.14ft
(0.96m)
2.7ft
(0.82m)
2.25ft
(0.69m)
1.86ft
(0.57m)
1.34ft
(0.41m)
* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).
5
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially
greater distances will be achieved at time of vegetation maintenance.
Draft 65: December 17, 2010June 17, 2011
26
FAC-003-23 — Transmission Vegetation Management
Table 2 (cont.) — Minimum Vegetation Clearance Distances (MVCD)
For Direct Current Voltages
sea level
MVCD feet
(meters)
3,000ft
(914.4m)
Alt.
MVCD feet
(meters)
4,000ft
(1219.2m)
Alt.
MVCD feet
(meters)
5,000ft
(1524m)
Alt.
MVCD feet
(meters)
6,000ft
(1828.8m)
Alt.
MVCD
feet
(meters)
7,000ft
(2133.6m)
Alt.
MVCD
feet
(meters)
(8,000ft
(2438.4m)
Alt.
MVCD
feet
(meters)
9,000ft
(2743.2m)
Alt.
MVCD
feet
(meters)
10,000ft
(3048m)
Alt.
MVCD
feet
(meters)
11,000ft
(3352.8m)
Alt.
±750
13.92ft
(4.24m)
15.07ft
(4.59m)
15.45ft
(4.71m)
15.82ft
(4.82m)
16.2ft
(4.94m)
16.55ft
(5.04m)
16.9ft
(5.15m)
17.27ft
(5.26m)
17.62ft
(5.37m)
17.97ft
(5.48m)
±600
10.07ft
(3.07m)
11.04ft
(3.36m)
11.35ft
(3.46m)
11.66ft
(3.55m)
11.98ft
(3.65m)
12.3ft
(3.75m)
12.62ft
(3.85m)
12.92ft
(3.94m)
13.24ft
(4.04m)
(13.54ft
4.13m)
±500
7.89ft
(2.40m)
8.71ft
(2.65m)
8.99ft
(2.74m)
9.25ft
(2.82m)
9.55ft
(2.91m)
9.82ft
(2.99m)
10.1ft
(3.08m)
10.38ft
(3.16m)
10.65ft
(3.25m)
10.92ft
(3.33m)
±400
4.78ft
(1.46m)
5.35ft
(1.63m)
5.55ft
(1.69m)
5.75ft
(1.75m)
5.95ft
(1.81m)
6.15ft
(1.87m)
6.36ft
(1.94m)
6.57ft
(2.00m)
6.77ft
(2.06m)
6.98ft
(2.13m)
±250
3.43ft
(1.05m)
4.02ft
(1.23m)
4.02ft
(1.23m)
4.18ft
(1.27m)
4.34ft
(1.32m)
4.5ft
(1.37m)
4.66ft
(1.42m)
4.83ft
(1.47m)
5ft
(1.52m)
5.17ft
(1.58m)
( DC )
Nominal Pole
to Ground
Voltage
(kV)
MVCD feet
(meters)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
Draft 65: December 17, 2010June 17, 2011
27
FAC-003-23 — Transmission Vegetation Management
•
•
•
avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
transmission lines operate in non-laboratory environments (wet conditions)
transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would
have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of
an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are
usually 1.5 per unit or less.
Draft 65: December 17, 2010June 17, 2011
28
FAC-003-23 — Transmission Vegetation Management
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is
considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1].
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage
Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various
transient overvoltage values.
Draft 65: December 17, 2010June 17, 2011
29
FAC-003-23 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations
vs.
IEEE 516-2003 MAID distances
using various transient over-voltage factors
Table 5
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
1.4
1.4
1.4
2.0
2.0
8.89
5.65
3.52
3.35
1.6
IEEE 516
MAID (ft)
@ Alt. 3000 feet
8.65
4.92
3.13
2.8
1.4
Table 5
(historical maximums)
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.0
2.4
3.0
3.0
3.0
14.36
11.0
8.55
5.28
2.46
Draft 65: December 17, 2010June 17, 2011
IEEE 516
MAID (ft)
@ Alt. 3000 feet
13.95
10.07
7.47
4.2
2.1
30
FAC-003-23 — Transmission Vegetation Management
Table 7
( AC )
Nom System
Voltage (kV)
( AC )
Max System
Voltage (kV)
Transient
Over-voltage
Factor (T)
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
765
500
345
230
115
800
550
362
242
121
2.5
3.0
3.5
3.5
3.5
20.25
15.02
10.42
6.32
2.90
Draft 65: December 17, 2010June 17, 2011
IEEE 516
MAID (ft)
@ Alt. 3000 feet
20.4
14.7
9.44
5.14
2.45
31
Implementation Plan for FAC-003-3 – Vegetation Management
Prerequisite Approvals
FAC-003-2 – Vegetation Management must be implemented before this standard can be
implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired
when FAC-003-3 becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already proposed
in FAC-003-2, and the expectation is that Transmission Owners will maintain their current state
of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to Version 2 of the standard only address Generator Owner applicability
and requirements (add Generator Owner to sections 4.1.2 and 4.3 and add applicable Generator
Owner to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of
as-built drawings and determine which generation interconnection Facilities require a
Transmission Vegetation Management Plan (TVMP) and inspection as specified by NERC
Reliability Standard FAC-003-3. In general, Generator Owners do not have staff that are
qualified and experienced to create a TVMP, perform Right-of-Way inspections, and perform
any required tree trimming (as is required by FAC-003-3 Requirement 1.3). Once a complete
inventory is created, the Generator Owner will begin the process of gathering information for the
TVMP. In instances where the generation interconnection Facilities are owned by a partnership,
a majority or operating partner will need to obtain partnership approval to proceed with
procurement of a TVMP expert, and later a tree trimming crew. Typically, a request for proposal
to hire TVMP consultant is initiated which could take several weeks in order to obtain sufficient
bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a contract
with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator
Owner staff and the TVMP consultant will need to perform a Right-of-Way inspection (as
required in FAC-003-3 Requirement 1), usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner
will need to issue a request for proposal to hire a tree trimming crew that is qualified and
experienced to perform required clearance trimming. Once all bids have been received, a
contract with a tree trimming crew is signed. When the tree trimming crew is acquired, the crew
will need to familiarize themselves with the entity's TVMP and required clearances. The
Generator Owner will typically need to schedule any required outages in order for the tree
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trimming crew to perform the needed clearance trimming. This action would also include the
implementation of the work plan as required in FAC-003-3 Requirement 2. During scheduled
outages, if required, the tree trimming crew will perform any required clearances and document
the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMPrelated activities, including maintenance of inspection and clearance documentation (as required
in FAC-003-3 Requirement 1.2). On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure that the
training and qualification requirements for the standard are met. The entity will also need to
maintain documentation of all FAC-003-3 activities for compliance period of one year to meet
compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance
with this standard by a Generator Owner may take as long as two years – in part because many
entities will have generator interconnection Facilities in various parts of the country which may
require several instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner
become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The third effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for is
required. In those jurisdictions where no regulatory approval is required, Requirements R1,
R2, R4, R5, R6, and R7 become effective on the first day of the first calendar quarter two
years following Board of Trustees adoption.
Exceptions:
2
A line operated below 200kV, designated by the Planning Coordinator as an element of
an IROL or as a Major WECC transfer path, becomes subject to this standard 12
months after the date the Planning Coordinator or WECC initially designates the line as
being subject to this standard.
An existing transmission line operated at 200kV or higher that is newly acquired by an
asset owner and was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line.
3
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain
lines.
1 of 12
Draft 1: June 17, 2011
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
4.1. Regional Entity.
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead Facility that extends greater than one
half mile beyond the fenced area of the switchyard, generating station or
generating substation up to the point of interconnection with the Transmission
system and is operated at 200 kV and above and any lower voltage lines
designated by the RE as critical to the reliability of the electric system in the
region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
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Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements applied to the Transmission Owner become effective upon
Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for is required. In those jurisdictions where no
regulatory approval is required, Requirements R2, R3, and R4 become effective on the first
day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
4 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its RE, or the RE’s designee, sustained transmission line outages determined by the applicable
Transmission Owner or applicable Generator Owner to have been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the RE, or the RE’s designee, certain sustained transmission line outages
caused by vegetation: (1) Vegetation-related outages that result from vegetation falling
into lines from outside the ROW that result from natural disasters shall not be
considered reportable (examples of disasters that could create non-reportable outages
include, but are not limited to, earthquakes, fires, tornados, hurricanes, landslides, wind
shear, major storms as defined either by the applicable Transmission Owner or
applicable Generator Owner or an applicable regulatory body, ice storms, and floods),
and (2) Vegetation-related outages due to human or animal activity shall not be
considered reportable (examples of human or animal activity that could cause a nonreportable outage include, but are not limited to, logging, animal severing tree, vehicle
contact with tree, arboricultural activities or horticultural or agricultural activities, or
removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the RE, or the RE’s designee, shall include at a minimum: the
name of the circuit(s) outaged, the date, time and duration of the outage; a description
of the cause of the outage; other pertinent comments; and any countermeasures taken
by the applicable Transmission Owner or applicable Generator Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The RE shall report the outage information provided to it by applicable Transmission Owners
or applicable Generator Owners, as required by Requirement 3, quarterly to NERC, as well as
any actions taken by the RE as a result of any of the reported outages.
[VRF – Lower]
C.
Measures
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
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Standard FAC-003-X — Transmission Vegetation Management Program
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the RE, or the RE’s designee, as identified in
Requirement 3.
M4. The RE has documentation that it provided quarterly outage reports to NERC as identified in
Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity for the Regional
Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
6 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
7 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
8 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
qualifications and
9 of 12
Draft 1: June 17, 2011
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
qualifications and
Standard FAC-003-X — Transmission Vegetation Management Program
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
10 of 12
Draft 1: June 17, 2011
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
Standard FAC-003-X — Transmission Vegetation Management Program
R3
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
11 of 12
Draft 1: June 17, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
X
May 16, 2011
Added requirements for Generator Owner
and brought overall standard format up to
date
12 of 12
Draft 1: June 17, 2011
Revision under Project
2010-07
Standard FAC-003-X1 — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain
lines.
The current glossary definition
of this NERC term wais
modified to allow both
maintenance inspections and
vegetation inspections to be
performed concurrently.include
applicable Generator Owners.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
A.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
1 of 13
Standard FAC-003-X1 — Transmission Vegetation Management Program
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X1
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Reliability Organizations Entity (RRORE) and the North American
Electric Reliability Council (NERC).
Applicability:
4.1. Regional Entity.
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead Facility that extends greater than one
half mile beyond the fenced area of the switchyard, generating station or
generating substation up to the point of interconnection with the Transmission
system and is operated at 200 kV and above and any lower voltage lines
designated by the RE as critical to the reliability of the electric system in the
region.
4.1.Transmission Owner.
4.2.Regional Reliability Organization.
4.3.
This standard shall apply to all transmission lines
operated at 200 kV and above and to any lower voltage lines
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
designated by the RRO as critical to the reliability of the electric
system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and
R4 applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for is required. In those jurisdictions where no
regulatory approval is required, Requirements R2, R3, and R4 become effective on the first
day of the first calendar quarter two years following Board of Trustees adoption.
5.1.One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
B.
Requirements
R1. The Each applicable Transmission Owner or applicable Generator Owner shall prepare, and
keep current, a formal transmission vegetation management program (TVMP). The TVMP
shall include the applicable Transmission Owner’s or applicable Generator Owner’s
objectives, practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicableThe Transmission Owner or applicable Generator Owner, in the
TVMP, shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicableEach Transmission Owner or applicable Generator Owner shall
develop mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable The Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicableThe Transmission Owner or applicable Generator Owner shall report quarterly
to its RERRO, or the RERRO’s designee, sustained transmission line outages determined by
the applicable Transmission Owner or applicable Generator Owner to have been caused by
vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the RERRO, or the RERRO’s designee, certain sustained transmission line
outages caused by vegetation: (1) Vegetation-related outages that result from
vegetation falling into lines from outside the ROW that result from natural disasters
shall not be considered reportable (examples of disasters that could create nonreportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the RERRO, or the RERRO’s designee, shall include at a
minimum: the name of the circuit(s) outaged, the date, time and duration of the outage;
a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The RERRO shall report the outage information provided to it by applicable Transmission
Owners or applicable Generator Owners’s, as required by Requirement 3, quarterly to NERC,
as well as any actions taken by the RERRO as a result of any of the reported outages.
R4.[VRF – Lower]
C.
Measures
M1. Each applicableThe Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicableThe Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicableThe Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicableThe Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicableThe Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicableThe Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable The Transmission Owner or applicable Generator Owner has documentation
that the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicableThe Transmission Owner or applicable Generator Owner has documentation
that it has supplied quarterly outage reports to the RERRO, or the RERRO’s designee, as
identified in Requirement 3.
M4. The RERRO has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.Compliance Monitoring ResponsibilityEnforcement Authority
1.2.1.1.
1.1.Compliance Monitor:
1.1.•
Regional Entity for the Transmission Owner and Generator Owner
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
• Electric Reliability Organization or another Regional Entity for the Regional
Entity
1.1.
RRO
NERC
1.2.Compliance Monitoring Period and Reset
1.2.
One calendar Yearand Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
E.
Data Retention
1.3.
The applicable Transmission Owner and applicable Generator Owner shall keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of
time as part of an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
Five Years
1.1.1.4.
Additional Compliance Information
1.4.None.
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
2.
Violation Severity Levels
R#
R1
Lower VSL
The responsible
entity did not
include and keep
current one of the
four required
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current two of the
four required
The responsible
entity did not
include and keep
current three of the
four required
The responsible
entity did not
include and keep
current all required
elements of the
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
R1.1
R1.2
elements of its
TVMP, as directed
by the
requirement.
N/A
elements of its
TVMP, as directed
by the
requirement.
N/A
N/A
N/A
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
R1.2.1
N/A
N/A
N/A
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
R1.2.2
R1.2.2.1
N/A
N/A
N/A
N/A
N/A
N/A
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
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Standard FAC-003-X1 — Transmission Vegetation Management Program
R1.2.2.2
R1.3
R1.4
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
N/A
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
N/A
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
For responsible
entities directly
entities directly
involving fewer
involving fewer
than 20 persons in than 20 persons in
the design and
the design and
implementation of implementation of
the TVMP, three
the TVMP, more
of those persons
than three of those
did not hold
persons did not
appropriate
hold appropriate
qualifications and
qualifications and
training to perform training to perform
their duties. For
their duties. For
responsible entities responsible entities
directly involving
directly involving
20 or more persons 20 or more persons
in the design and
in the design and
implementation of implementation of
the TVMP, more
the TVMP, more
than 10% up to
than 15% of those
(and including)
persons did not
15%of those
hold appropriate
persons did not
qualifications and
hold appropriate
training to perform
qualifications and
their duties.
training to perform
their duties.
N/A
The responsible
entity's TVMP
does not include
mitigation
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Standard FAC-003-X1 — Transmission Vegetation Management Program
R1.5
R2
R3
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
OR
The responsible
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
management.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
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Standard FAC-003-X1 — Transmission Vegetation Management Program
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
N/A
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
N/A
N/A
N/A
E.
2.Levels of Non-Compliance
2.1.Level 1:
2.1.1.The TVMP was incomplete in one of the requirements specified in any subpart
of Requirement 1, or;
2.1.2.Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2.Level 2:
2.2.1.The TVMP was incomplete in two of the requirements specified in any subpart
of Requirement 1, or;
2.2.2.The Transmission Owner was unable to certify during its annual self-certification
that it fully implemented its annual work plan, or documented deviations
from, as specified in Requirement 2.
2.2.3.The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
2.3.Level 3:
2.3.1.The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.The Transmission Owner did not maintain a set of clearances (Clearance 2), as
defined in Requirement 1.2.2, to prevent flashover between vegetation and
overhead ungrounded supply conductors, or;
2.3.3.The TVMP was incomplete in three of the requirements specified in any subpart
of Requirement 1.
2.4.Level 4:
2.4.1.The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
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Standard FAC-003-X1 — Transmission Vegetation Management Program
2.4.2.The TVMP was incomplete in four or more of the requirements specified in any
subpart of Requirement 1.
G.E. Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
May 16, 2011
Added requirements for Generator Owner
and brought overall standard format up to
date
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 1: April 7, 2006June 17, 2011
Revision under Project
2010-07
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Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired when FAC-003-2 becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
1
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMP and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
2
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for is
required. In those jurisdictions where no regulatory approval is required,
Requirements R2, R3, and R4 become effective on the first day of the first calendar
quarter two years following Board of Trustees adoption.
3
Project 2010-07:
Generator Requirements at the Transmission Interface
Background Resource Document
Introduction
The integrated grid consists of many parts such as power plants, Transmission, and Facilities 1, some
of which are known as generator interconnection Facilities and operate like extension cords to
connect generating plants to the overall interconnected grid. Some plants consist of just a single
generating unit, other plants consist of multiple generating units, and still others consist of multiple
generating units spread over several thousand acres. While not all power plants and their associated
Facilities are considered part of the Bulk Electric System (BES) 2, of concern is how to classify all
such generating Facilities, including their generator interconnection Facilities, to ensure that NERC’s
Reliability Standards provide an appropriate level of reliability for the BES.
When such generator interconnection Facilities are owned by the Generator Owner, are part of the
BES, and meet the criteria in the Statement of Compliance Registry Criteria, the Project 2010-07—
Generator Requirements at the Transmission Interface standard drafting team (drafting team)
concludes that such Facilities are only to be included in the reliability standards requirements
applicable to the Generator Owner or Generator Operator. To ensure that responsibility for the
generator interconnection Facilities is included in all necessary standards, however, a select number
of standards need to have Generator Owners added to their applicability.
Objective
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. The drafting team believes it is appropriate to classify
various generating Facilities and Elements (sometimes including generator interconnection Facilities)
as part of the BES. That does not mean, however, that a Generator Owner or Generator Operator
should be required to automatically register as a Transmission Owner or Transmission Operator
simply because it owns and/or operates BES Elements or Facilities that are considered by some
entities to be Transmission. While Generator Owners and Generator Operators meeting the criteria in
the Statement of Compliance Registry Criteria own and operate Elements and Facilities that are
considered by some entities to be Transmission, these are most often not part of the integrated grid,
and as such should not be subject to all of the same standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Elements and Facilities that are part of
the integrated grid.
1
“Facility” is defined in NERC’s Glossary of Terms as “A set of electrical equipment that operates as a single Bulk
Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.).”
2
The current definition of “Bulk Electric System” in the NERC’s Glossary of Terms reads: “As defined by the
Regional Reliability Organization, the electrical generation resources, transmission lines, interconnections with
neighboring systems, and associated equipment, generally operated at voltages of 100 kV or higher. Radial
transmission facilities serving only load with one transmission source are generally not included in this definition.”
The drafting team interprets “electrical generation resources” as inclusive of generator interconnection Facilities.
Note that this definition is undergoing significant revision under Project 2010-17—Definition of Bulk Electric
System.
1
When the Elements and Facilities owned and operated by Generator Owners and Generator
Operators are considered by some entities to be Transmission and deemed part of the integrated grid,
registering the Generator Owner or Generator Operator as a Transmission Owner or Transmission
Operator is appropriate. But most often the Facilities are limited to interconnecting generation to the
Transmission system and as such have little, if any, measurable effect on the overall reliability of the
BES. In fact, registering a Generator Owner or Generator Operator as a Transmission Owner or
Transmission Operator may decrease reliability by diverting the Generator Owner’s or Generator
Operator’s attention from the operation of the equipment that actually produces electricity – the
generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying selected standards or specific standard requirements to Generator Owners and
Generator Operators. The drafting team recommends a plan to modify the requirements and measures
of a selected number of standards to make them applicable to appropriate Generator Owners and
Generator Operators.
Proposed Next Steps and Review of Reliability Standards
Below, the drafting team outlines its recommendations to clearly identify the appropriate generation
Facilities and standards requirements that should apply to such generation Facilities to ensure that the
reliability of the BES is maintained:
FAC-001-0—Facility Connection Requirements currently applies to Transmission Owners and
addresses the need for Transmission Owners to establish Facility connection and performance
requirements for interconnection to their Facilities. Because Generator Owners may be requested to
allow interconnection to their Facilities, the STD recommends the following:
•
Revise FAC-001 so that it applies to a Generator Owner if, and when, it executes an
Agreement to evaluate the reliability impact of interconnecting another Facility to its existing
generation Facility. (See accompanying draft standard FAC-001-1.)
o In its first posting for informal comment, the drafting team set the “trigger” for the
application of FAC-001 as the receipt of a request for interconnection. Many
commenters disagreed with this approach and suggested that the “trigger” be based
upon “the intent or obligation” to interconnect a new Facility to an existing
interconnecting Facility that is owned by a generator. Accordingly, the drafting team
has proposed language to addresses this concern. The intent of this modified language
is to start the compliance clock at such time as the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step
should occur whether the generator voluntarily agrees to the interconnection request
or is compelled by a regulatory body to do so. In either case, we expect the Generator
Owner and the requestor to execute some form of Agreement. We intentionally
excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to comments that we should avoid comingling of commercial and
reliability aspects in reliability standards.
2
FAC-003-2—Vegetation Management currently applies to Transmission Owners and addresses the
need to maintain a reliable electric transmission system by using a defense-in-depth strategy to
manage vegetation located on transmission Rights-of-Way (ROW) and minimize encroachments
from vegetation located adjacent to the ROW. It has been a major concern that certain types of
Facilities used to interconnect generation be required to provide the same level of vegetation
management as required for the Transmission Owner operating in the BES. Numerous comments
requested a specific length for the interconnecting line before considering application of the standard.
The drafting team recommends:
•
Revise FAC-003 so that it applies to Generator Owners that own a Facility that extends
greater than one half mile beyond the fenced area of the switchyard, generating station or
generating substation (up to the point of interconnection with the Transmission system). (See
accompanying draft standards FAC-003-X and FAC-003-3.)
o The drafting team elected to use the half-mile qualifier in its latest proposed changes.
The GOTO Ad Hoc Group had originally proposed something similar, but their
proposed criterion was a length of “two spans (generally one half mile from the
generator property line).” The drafting team elected to use only the half-mile qualifier
because it has been supported by industry comment and is clearer than referencing
both two spans and the half-mile length. This distance is within the Generator
Owner’s line of sight and could be visually monitored for vegetation conditions on a
routine basis. Beyond the distance of one half mile, a vegetation management
program is necessary to manage the Right-of-Way.
o The drafting team also added text boxes to each proposed standard modification to
help define certain terms within the context of the standard, rather than propose
defined terms.
At this stage, the drafting team is developing two versions of proposed revisions to FAC-003: one to
FAC-003-1, the current FERC-approved version of the standard (labeled FAC-003-X in
accompanying documents) and one to FAC-003-2, the proposed version currently under development
under Project 2007-07 (the Project 2010-07 team is labeling its revisions as FAC-003-3). See the
accompanying proposed redline standards for further justification and detail.
The proposed changes listed above mark a significant decrease in changes originally proposed by the
GOTO Ad Hoc Group in its Final Report. The drafting team has again reviewed every reliability
standard included in that report, as well as MOD and TPL standards identified in comments it has
received. The drafting team does not believe that changes to reliability standards other than FAC-001
and FAC-003 are necessary to close any reliability gaps associated with generator interconnection
Facilities that are non-network/non-integrated in nature (typically radial and used solely for the
purpose of connecting the generating unit or units to the Transmission Facilities). Below, the drafting
team has included its notes about why no other standards require modification as part of this project.
The standards highlighted here are those about which questions were raised by commenters or
regulatory staff:
•
•
COM-001-1.1: This standard applies to entities with a wide-area view. The related
responsibilities for Generator Operators are already addressed in COM-002-2.
EOP-005-2: There was some concern that EOP-005 did not properly account for the
Generator Operator’s responsibility when it comes to system restoration plans, but EOP-0053
•
•
•
•
•
•
2, R13 (which received regulatory approval on May 23, 2011) requires Generator Operators
to have written Blackstart Resource Agreements or mutually agreed upon procedures or
protocols with its Transmission Operator. Requirements R14 through R18 require the
Generator Operator to develop procedures, test its blackstart generators, and provide related
training.
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, MOD-030-2: To
apply these standards to Generator Operators would require them to have a wide-area view of
the integrated grid and to utilize commercially sensitive information that Generator Operators
are currently precluded from viewing or using. In some cases, such as with MOD-001, the
standard could only apply if a Generator Operator was registered as a Transmission Service
Provider due to an interconnection service request and subsequently adopted an Open Access
Transmission Tariff. The drafting team does not believe this is likely, unless ordered by
FERC.
PER-002-0: In Order 693, FERC directed NERC to “expand the applicability of the
personnel training in Reliability Standard, PER-002-0, to include (i) generator operators
centrally-located at a generation control center with a direct impact on the reliable operation
of the Bulk-Power System...” In Order 742, the Commission said it is “not modifying the
Order No. 693 directive regarding training for certain generator operator dispatch personnel,
nor are we expanding a generator operator’s responsibilities.” This issue does not deal with
generator interconnection Facilities and is thus outside the scope of Project 2010-07. The
directive has been included in NERC’s issues database to be addressed in a future project.
PRC-001-1: Generator Operators are already appropriately accounted for in this standard in
requirements 1, 2, 3, and 5.
TOP-003-0: TOP-003-0 already requires the Generator Owner to provide outage information
to its Transmission Operator on a daily basis. Proposed TOP-003-2 R4 continues to make this
responsibility clear by requiring Generator Owners and Generator Operators to satisfy the
obligations of the Transmission Owner’s and Transmission Operator’s data specification
plan.
TOP-006-2: TOP-006-2 deals with general issues with generator reporting. Though not
explicitly stated, Requirement R2 requires reporting of scheduled outages of equipment such
as voltage regulators, shunt capacitors, etc. The drafting team believes that Elements
associated with a generator interconnection Facility are to be reported under this requirement
VAR-001-1: This standard also requires a wide-area view that is inappropriate for a
Generator Operator. Generator Operators, for instance, should never be setting voltage
schedules.
VAR-002-1.1b: The drafting team received some comments expressing concern about
capacitors under operational control of the Generator Operator. Requirement R3.2 requires
notification for status or capability change on any other Reactive Power resources under the
Generator Operator’s control and the expected duration of the change in status or capability.
The drafting team believes that capacitors are included in this requirement.
The drafting team also decided not to propose new defined terms in the NERC Glossary, but has met
with NERC and FERC staffs, regional compliance managers and industry organizations to discuss
possible solutions to the issue of concern to most Generator Owners and Generator Operators –
registration as Transmission Owners and Transmission Operators. The drafting team believes this
issue has the attention of appropriate NERC and regional staffs and has volunteered to provide
assistance in those groups’ efforts to address them. While these changes are not within the explicit
4
scope of the drafting team, the goal is to work with NERC and regional compliance enforcement and
compliance registration staffs to develop a comprehensive package that will address all reliability
gaps – whether real or perceived – so that entities are appropriately registered and the appropriate
reliability standards are applied to those entities.
The drafting team acknowledges that there may be Elements and Facilities that are not radial or used
solely for the purpose of connecting the generating unit(s) to Transmission Facilities. It is outside the
scope of the drafting team to address this as part of its project, but it believes that the best way to
address these non-radial Facilities is through changes to the criteria in the Statement of Compliance
Registry Criteria as they apply to Generator Owner or Generator Operator. Trying to apply simple
‘bright line’ criteria to such Facilities as a drafting team would be a daunting task, as the
configuration of interconnections is not consistent continent-wide, nor are all adjacent Elements and
Facilities similar. Addressing these non-radial generator interconnection Facilities will require
individual evaluations to ensure that no reliability gaps exist, and this is a task best suited to
compliance staffs.
The drafting team also acknowledges that, if another party interconnects to a Facility owned by a
Generator Owner, there may be the need to address MOD or TPL standards. However, the drafting
team believes that this, too, is best handled through specific evaluation, perhaps accompanied by
changes to the compliance registry. Entities that face this kind of scenario may also meet criteria
applicable to other registrations such as Transmission Service Provider or Transmission Planner.
Other Solutions
Because the efforts outlined here will likely not take effect for a year or more, Generator Owners and
Generator Operators that are concerned about their registration status should explore options like
those explained below and in further detail in NERC Compliance Bulletin 2010-004.
On April 20, 2010, NERC Compliance published a Public Bulletin to provide guidance for situations
like this, in which entities delegate reliability tasks to a third-party entity. In this bulletin, NERC
Compliance emphasizes that while a registered entity may not delegate its responsibility for ensuring
that a task is completed, it may delegate the performance of a task to another entity.
As is explained in the bulletin, compliance responsibility for applicable NERC Reliability Standard
requirements and accountability for violations thereof may be achieved through several means,
including the following:
1. By Individual: an entity is registered on the NERC Compliance Registry and such registered
entity assumes full compliance responsibility and accountability; or
2. By Written Contract: parties enter into written agreement whereby:
a. A registered entity delegates the performance of some or all functional activities to a third party
that is not a registered entity, and the registered entity retains full compliance responsibility and
violation accountability; or
b. A registered entity delegates the performance of some or all of the functional activities to a third
party, and the third party accepts full compliance responsibility for the specific functions it performs
and violation accountability. In this case, there may be individual, concurrent or joint registration of
5
the entities, depending on the nature of the contractual relationship and, in any event, only the
registered entity would be held responsible or accountable by a Regional Entity or NERC; or
3. By Joint Registration Organization (JRO): each party is registered and is required to clearly
identify and allocate compliance responsibility and violation accountability for their respective
functions under applicable NERC Reliability Standard requirements.
6
Unofficial Comment Form for Project 2010-07—Generator
Requirements at the Transmission Interface
Please DO NOT use this form to submit comments. Please use the electronic comment form
located at the link below to submit comments on the first formal posting for Project 201007—Generator Requirements at the Transmission Interface. The electronic comment form
must be completed by July 17, 2011.
Project 2010-07—Generator Requirements at the Transmission Interface
If you have questions please contact Mallory Huggins at mallory.huggins@nerc.net or 202383-2629.
This is the first 30-day formal comment period for the standards included in Project 201007. A 30-day informal comment period took place earlier this year, from March 4 to April 4,
2011. The team thanks all those who provided feedback during that comment period. The
team has reviewed and considered all comments submitted, and has incorporated many of
them into its latest proposed standards, as explained in the Summary Response to Informal
Comment posted at the Project 2010-07 project page.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are
appropriately covered under NERC’s Reliability Standards. While many Generator Owners
and Generator Operators operate Elements and Facilities that are considered by some
entities to be Transmission, these are most often radial Facilities that are not part of the
integrated grid, and as such should not be subject to the same standards applicable to
Transmission Owners and Transmission Operators who own and operate Transmission
Elements and Facilities that are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. However, registering
a Generator Owner or Generator Operator as a Transmission Owner or Transmission
Operator, as has been the solution in some cases in the past, may decrease reliability by
diverting the Generator Owner’s or Generator Operator’s resources from the operation of
the equipment that actually produces electricity – the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the
BES by clearly describing which standards need to be applied to generator interconnection
Facilities that are not already applicable to Generator Owners or Generator Operators. This
can be accomplished by properly applying FAC-001 and FAC-003 to Generator Owners as
proposed in the redline standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the
background resource document it has provided to describe its rationale and its work thus
far.
You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. Do you support the proposed redline changes to FAC-001-1?
Yes
No
Comments:
2. Do you support the one year compliance timeframe for Generator Owners as proposed in
the Implementation Plan for FAC-001-1?
Yes
No
Comments:
3. Taking into consideration that only one of the versions of FAC-003 will actually be
implemented, a decision that will be made as the Project 2010-07 drafting team learns
more about the status of Project 2007-07—Vegetation Management, do you support the
proposed redline changes to FAC-003-X and FAC-003-3?
Yes
No
Comments:
4. The drafting team has added Generator Owners to the Applicability sections of FAC-003X and FAC-003-3 with the qualifier that the included lines “extend greater than one half
mile beyond the fenced area of the switchyard, generating station or generating
substation up to the point of interconnection with the Transmission system.” The team
received many comments about the need to define a distance rather than other
measures for exclusion, and decided on the one half mile as a reasonable distance. Do
you agree with this half-mile qualifier?
Yes
No
Comments:
5. Do you support the two year compliance timeframe for Generator Owners as included
and explained in the Implementation Plans for FAC-003-X and FAC-003-3?
Yes
No
Comments:
6. In its background resource document, the drafting team lists the standards that it has
not modified, and offers rationale for its decisions. Are there any reliability standards or
requirements that you believe should apply to Generator Owners or Generator Operators
that own and are responsible for the operation of an overhead Facility, that are not
already applicable or have been proposed to be applicable (FAC-001 and FAC-003) by
the Project 2010-07 drafting team? If so, please list them and offer an explanation as to
why they should be applicable to that entity.
Yes
No
Comments:
7. Do you have any other questions or concerns with the proposed standards or with the
background resource document that have not been addressed? If yes, please explain.
Yes
No
Comments:
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Formal Comment Period Open June 17 – July 17, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
The Generator Requirements at the Transmission Interface standard drafting team has posted proposed modifications
to FAC-001 and FAC-003, along with a background resource document, for a formal comment period. For FAC003, the team has posted proposed changes to two versions of the standard: FAC-003-1, the current FERC-approved
version of the standard, has been modified as FAC-003-X, and FAC-003-2, the version currently under development
by the Project 2007-07 —Vegetation Management drafting team has been modified as FAC-003-3. The 30-day
formal comment period will end at 8 p.m. Eastern on Sunday, July 17, 2011.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Next Steps
The drafting team will consider all comments submitted and make revisions to the draft standards to address
issues identified by commenters. The team will submit its work for quality review, and following the quality
review, the team’s consideration of comments will be posted, along with the revised standards, associated
implementation plans, and supporting documents. The standards will then be posted for a 45-day formal
comment period with an initial ballot conducted during the last 10 days of the comment period.
Background
This is the first 30-day formal comment period for the standards included in Project 2010-07. A 30-day
informal comment period took place earlier this year, from March 4 to April 4, 2011. The team thanks all those
who provided feedback during that comment period. The team has reviewed and considered all comments
submitted, and has incorporated many of them into its latest proposed standards, as explained in the Summary
Response to Informal Comment posted at the Project 2010-07 project page.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately covered under
NERC’s Reliability Standards. While many Generator Owners and Generator Operators operate Elements and
Facilities that are considered by some entities to be Transmission, these are most often radial Facilities that are
not part of the integrated grid, and as such should not be subject to the same standards applicable to
Transmission Owners and Transmission Operators who own and operate Transmission Elements and Facilities
that are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. However, registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the solution in
some cases in the past, may decrease reliability by diverting the Generator Owner’s or Generator Operator’s
resources from the operation of the equipment that actually produces electricity – the generation equipment
itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by clearly
describing which standards need to be applied to generator interconnection Facilities that are not already
applicable to Generator Owners or Generator Operators. This can be accomplished by properly applying FAC001 and FAC-003 to Generator Owners as proposed in the redline standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the background resource
document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page at http://www.nerc.com/filez/standards/Project201007_GOTO_Project.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Individual or group. (41 Responses)
Name (24 Responses)
Organization (24 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
Question 1 (37 Responses)
Question 1 Comments (41 Responses)
Question 2 (35 Responses)
Question 2 Comments (41 Responses)
Question 3 (36 Responses)
Question 3 Comments (41 Responses)
Question 4 (37 Responses)
Question 4 Comments (41 Responses)
Question 5 (36 Responses)
Question 5 Comments (41 Responses)
Question 6 (36 Responses)
Question 6 Comments (41 Responses)
Question 7 (36 Responses)
Question 7 Comments (41 Responses)
Group
Bonneville Power Administration
Chris Higgins
Yes
Yes
Yes
No
BPA believes that there needs to be a clear demarcation where Transmission Owner and Generator
Owner responsibilities begin and end.
Yes
Yes
No
Group
Notheast Power Coordinating Council
Guy Zito
Yes
Yes
No
See comments in the following questions.
No
The qualifier should be similar to that specified in Part 4.2.4 of FAC-003-3: “This standard applies to
overhead transmission lines identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the transmission line that is
crossing the substation fence. “ Vegetation needing attention can exist within a half mile of a
switchyard. Vegetation does not discriminate between Generation and Transmission Owners.
Yes
Yes
Regarding the Right-of-Way definitions, the definition in FAC-003-3 is the better of the two. Suggest
adding “and maintain” to the first sentence of the definition as follows: The corridor of land under a
transmission line(s) needed to operate and maintain the line(s). The width of the corridor is
established by engineering or construction standards as documented in either construction
documents, pre-2007 vegetation maintenance records, or by the blowout standard in effect when the
line was built. The ROW width in no case exceeds the applicable Transmission Owner’s or applicable
Generator Owner’s legal rights but may be less based on the aforementioned criteria. The term Rightof-Way goes beyond Transmission Vegetation Management, and that should be considered in the
definition. How does Right-of-Way affect transmission facilities that are routed over bodies of water,
or over valleys, highways, etc.? Right-of-Way in relation to underground facilities? The format of FAC003-X should be made consistent with current NERC guidelines (i.e.--Parts of Requirements should
not have R’s in their numbering, should be 1.1, 1.2 etc.).
Individual
Mike Laney
Luminant Power
Yes
Yes
Yes
Yes
Yes
No
No
Group
SERC OC Standards Review Group
Gerald Beckerle
Yes
Consider a better definition of what constitutes an “applicable” generator owner or point to the
document that explains the definition.
No
We feel that an 18 month implementation plan would be more conducive for generators to meet these
new requirements
Yes
Yes
While we agree, we believe that a better explanation of “the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection with the Transmission
system” should be included. One suggestion is to distinguish between a plant perimeter fence and an
internal switchyard fence.
Yes
No
No
Group
EPSA
Jack Cashin
Background The Electric Power Supply Association (EPSA) endorsed the initial recommendations of
the Ad Hoc Group for Generator Requirements at the Transmission Interface, offered informal
comments on the March 2011 White Paper Proposal for Project 2010-07 and now appreciates this
opportunity to provide comments on the questions posted June 17, 2011. Since NERC’s creation of
the “GOTO Team” in February of 2009, EPSA has supported the efforts of Ad-Hoc Group and now the
Project 2010-07 Standards Drafting Team (SDT). While EPSA members’ compliance registration
includes several functional entity types, the bulk of competitive suppliers’ registrations are as
Generator Owners (GOs) and Generator Operators (GOPs). EPSA applauds the SDT’s decision to
recommend the use the “intent of obligation” as the reason for application of FAC-001 rather than the
receipt of request for interconnection and thereby supports the revisions to FAC-001-1. The proposed
modification to FAC-001 (a new R2) would require a GO to develop “Facility connection requirements”
within “45 days of executing an Agreement to evaluate the reliability impact of interconnecting
another Facility to its existing generation Facility…” The use of the agreement execution is a more
reasonable triggering mechanism for FAC-001 application and compliance. The SDT’s recommendation
intentionally excluded specific reference to the form of agreement to avoid commingling commercial
and reliability aspects in reliability standards. However, the existing language may still may mix
commercial and reliability issues. The accompanying project Background Resource Document (p.2)
makes it clear that the interconnection to an existing generator facility is contemplated to be the
“existing interconnecting Facility that is owned by a generator” – that is, the generator’s lead. The
generator’s leads are considered part of the “existing generator Facility,” however, the generator,
step-up transformer and other equipment that is within the generator switchyard can also be
considered part of the Facility. FERC requires all transmission facilities to be available for “open
access.” A generator lead would become open access if another customer interconnected to it.
Therefore FAC-001-1 could be made clearer by modifying the language regarding the 45-day trigger
as follows: within “45 days of executing an Agreement to evaluate the reliability impact of
interconnecting another Facility to its the Generator Owner’s existing generation interconnecting
transmission Facilities…” This modification would make it clear that the requirement does not apply to
an entity that wants to, for example, connect a new generator within the fenced-in site of the existing
generator, but instead only applies to request to interconnect to the generator lead.
Yes
Yes
EPSA generally supports the SDT’s proposed redline changes to FAC-003-X and FAC-003-3 and SDT’s
diligence in monitoring Project 2007-07. There is one distinction however that EPSA would like to
bring to the SDT’s attention that could increase clarity. FAC-003-X and FAC-003-3 both have similar
“one half mile” language, but the starting point for the one half mile can occur one of three ways. In
FAC-003-X, the language in 4.3.1 reads “Generator Owner that owns an overhead Facility that
extends greater than one half mile beyond the fenced area of the switchyard, generating station or
generating substation up to the point of interconnection with the Transmission system and …”
Therefore, there are three possible staring points for the measurement of the one half mile: beyond
the fenced area of (i) the switchyard, (ii) the generating station, or (iii) the generation substation.
While it would appear implicit that GO’s would determine which of the three was used to make the
determination that the GO determines the starting point. Another point for consideration is that a
Generator Owner’s overhead Facility that is within the fence should explicitly not be applicable to the
standard. EPSA believes the language that refers to the “interconnection with the Transmission
system” should be changed to “interconnection with a Transmission Owner’s Facility. The reason is
that the term “Transmission” which is defined in the NERC Glossary could be construed to include all
of a Generator Owner’s interconnection leads. Therefore, we suggest that the language in 4.3.1 be
modified as follows to make all of these points clear: A Generator Owner that owns an overhead
Facility that extends greater than one half mile beyond the fenced area of either the generator
switchyard, generating station or generating substation (as specified by the Generation Owner) up to
the point of interconnection with the Transmission Owner’s Facility and is operated 200 kV and above
and any lower voltage lines designated by the RE as critical to the reliability of the electric system
within the region is applicable to this standard.”
Yes
EPSA appreciates the SDT proposing to use the approach that provides a specific distance for
determining which GO Facility lead lines that FAC-003 should apply to. EPSA agrees that the half-mile
qualifier provides a discrete parameter that will limit ambiguity in the Standard.
Yes
No
Yes
EPSA can appreciate the SDT’s decision that it not propose new defined terms for the NERC Glossary.
The SDT bases the decision on outreach meetings with NERC, regional compliance managers and
industry organizations. EPSA supports outreach but still believes that the SDT should propose
definitions for the NERC Glossary. The definitions can serve as a basis for the outreach meetings while
also further limiting reliability gaps – real or perceived. Much as EPSA expressed in its White Paper
comments there is still a need for a definition for generator interconnection facilities. In addition,
because integrated transmission facility has also played a big part in the cases that have prompted
the need for Project 2010-07 the drafting team should propose a glossary change for that definition
as well. A definition for generation interconnection facilities is necessary in Project 2010-07 Standard
so that the interface between generators and transmission system can be clearly established and any
ambiguities about reliability responsibilities for GOs & GOPs and TO & TOPs can be eliminated. EPSA
recommended the definitions from the Ad-Hoc Group Report could be used for incorporating the
Generator Interconnection Facility into the standard: Generator Interconnection Facility Sole-use
facility for the purpose of connecting the generating unit(s) to the transmission grid. In this regard,
the sole-use facility only transmits power associated with the interconnecting generator, whether
delivered to the grid or delivered to the generator for station service or auxiliary load, or delivered to
meet cogeneration load requirements. Generator Interconnection Operational Interface Location at
which operating responsibility for the Generator Interconnection Facility changes between the
Transmission Operator and the Generator Operator. These definitions were developed with due
consideration for varying configurations, outages, and generators materiality to the BES. The Facility
definition defines the purpose of the facility, while the Generator Interconnection Operational
Interface definition provides the functional lines of demarcation between the GO and the TO. The
definitions were developed based on the purpose of generator interconnection facilities, their usage
and how their usage differs from transmission facilities that comprise the interconnected grid. Similar
to EPSA’s assertions on the White Paper competitive suppliers believe this is a sound basis for
distinguishing BES facilities. EPSA also suggests that the SDT include the following proposed definition
for Integrated Transmission Facilities for inclusion in the NERC Glossary: Integrated Transmission
Facilities (ITF) ITF are the Facilities that are a subpart of Transmission system that are capable of
carrying the flows from multiple generator plants at different points of interconnection for delivery to
customers, or to other electric systems. This proposed ITF definition builds upon Commission
precedent in the Open Access Transmission Tariff (OATT) area. FERC has recognized that facilities
that can carry flows from multiple supply points and deliver that power to either customers or other
electric systems are proper facilities to include in an OATT and define the “Transmission System” for
OATT purposes. The term “Transmission System” is an OATT-defined term that means “The facilities
owned, controlled or operated by the Transmission Provider that are used to provide transmission
service under Part II [Point-to-Point Transmission Service] and Part III [Network Integrated
Transmission Service] of the Tariff.” Under Commission precedent, facilities such as generator step-up
transformers and generator interconnecting transmission facilities have been excluded from the
OATT; i.e., they are not facilities that provide Transmission Service because they cannot carry the
flows from multiple supply points for delivery to customers or other electric system – their only use is
to the GO and perform two functions: 1. They deliver power from the GO’s generators at a site to the
OATT-defined Transmission System, and 2. They deliver off-site power from the OATT-defined
Transmission System to the generators at a site when the generators at a site are not operating.
While building on FERC OATT precedent, the proposed definition of “Integrated Transmission
Facilities” does not require an applicable Transmission Service tariff to identify those facilities.
Integrated Transmission Facilities are simply defined as those that capable of carrying flows from
multiple supply points for delivery to customers or to other electric systems. Using the ITF definition,
the definition of Generation Owner could be modified as follows: Generation Owner The Entity that
owns and maintains generating units but which does not own or maintain Integrated Transmission
Facilities. EPSA encourages the Project 2010-07 SDT to consider fitting the above definitions into the
current proposal for inclusion in the NERC Glossary. Therefore, EPSA respectfully requests that the
SDT for Project 2010-07 consider the all the recommendations made herein to the seven questions.
Individual
Thad Ness
American Electric Power
No
There are substantial reliability issues, as well as additional regulatory, tariff, coordination, and
generator and interconnection facility issues, which need to be dealt with before AEP could agree to
such requirements. It is not clear that a generator can receive a request for interconnection. We
recommend adding qualifier text which states the standard only applies *if* an entity plans to allow
such a requested interconnection. This would allow an entity to document that they do not plan to
allow such interconnections.
Yes
Yes
Yes
Yes
No
Individual
Edward Cambridge
APS
No
Do not agree with adding GO to FAC-001-1
No
Leave the GO out of the standard.
No
Leave the GO out of both Standards proposed.
No
Leave GOs out of the standards.
No
Leave GOs out of the standards.
No
Leave GOs and GOPs out of the FAC-001 and FAC-003 standards.
Yes
Leave GOs out of the standards,because it just adds more regulation and reporting requirements not
needed.
Individual
Gretchen Schott
BP Wind Energy North America Inc.
Yes
Yes
Yes
Yes
Yes
No
No
Group
PacifiCorp
Sandra Shaffer
Yes
Yes
Yes
Yes
Yes
No
Yes
PacifiCorp believes the Standards Drafting Team should clarify the Transmission Owner and/or the
Generator Owner are not required to provide evidence, documentation, notification, or inspection of
vegetation management for facilities not owned by the Transmission Owner and/or the Generator
Owner.
Individual
Katy Mirr
Sempra Generation
Yes
Sempra Generation supports the proposal for the compliance obligations under R2 associated with an
interconnection request not to be triggered until an interconnection study agreement has been
executed.
Yes
Yes
Yes
Yes
No
No, Sempra Generation believes the Project 2010-07 Team has effectively indentified the Standards
and Requirements that should apply to Generator Owners or Generator Operators that own, and are
responsible for, the operation of an overhead Facility, that are not already applicable or have been
proposed to be applicable.
Yes
When implemented, the recommendations of the Project 2010-07 Team go a long way toward
providing the regulatory and compliance certainty needed by generators who own or operate
Generator Interconnection Facilities. NERC is encouraged to provide these industry-supported
amendments to the NERC Board of Trustees in the near future. Sempra Generation also supports the
comments, being concurrently filed, of the Electric Power Supply Association (EPSA).
Individual
Brian Evans-Mongeon
Utility Services, Inc.
Yes
In one of the supporting documents for the upcoming comments, the GO/TO group included the
following statement in support for the rationale on FAC-001. In its first posting for informal comment,
the drafting team set the “trigger” for the application of FAC-001 as the receipt of a request for
interconnection. Many commenters disagreed with this approach and suggested that the “trigger” be
based upon “the intent or obligation” to interconnect a new Facility to an existing interconnecting
Facility that is owned by a generator. Accordingly, the drafting team has proposed language to
addresses this concern. The intent of this modified language is to start the compliance clock at such
time as the Generator Owner executes an Agreement to perform the reliability assessment required in
FAC-002-1. This step should occur whether the generator voluntarily agrees to the interconnection
request or is compelled by a regulatory body to do so. In either case, we expect the Generator Owner
and the requestor to execute some form of Agreement. We intentionally excluded a specific reference
to the form of Agreement (such as a feasibility study) in deference to comments that we should avoid
comingling of commercial and reliability aspects in reliability standards. I wonder about whether or
not this can work timing-wise. It says the compliance clock starts with the agreement to perform the
reliability assessment for FAC-002. The FAC-001 requirements outline the need for a registered entity
to document, maintain, and publish facility connections requirements in order to be compliant. If the
clock starts at the agreement for the assessment, does that mean that you then document, maintain,
and publish the connection requirements? Don’t the connection requirements usually outline the
terms for the “agreement for the assessment”? I am not sure that I understand the timing sequence
in order to be compliant to the standard. I would think that the agreement needs to be in place at the
time of the effective date of the standard, not upon an application.
Individual
Samuel Reed
Tri-State Generation and Transmission, Inc.
Yes
Yes
Yes
Yes
Yes
No
No
Individual
Alice Ireland
Xcel Energy
Yes
We believe it would be helpful to put explanatory wording in that if an entity is already registered as a
Transmission Owner and Generator Owner, the Generator Owner portion of that entity would not have
to have a separate set of interconnection requirements.
Yes
Yes
Yes
Yes
No
No
Group
Midwest Reliability Organization's NERC Standards Review Forum (NSRF)
Carol Gerou
No
In general, the NSRF supports the changes to FAC-001-1. However the 45 days to exicute an
agreement would be a significant burden on a Generator Operator that does not have an existing
process in place. The NSRF believes an aggressive but realistic time frame is 120 days. This would
allow sufficient time to develop the procedure and obtain the necessary technical and legal reviews.
Please clarify why "Procection" is capitalized in section 3.1.5. "Protection System" is defined by NERC
but "System Protection" is not. Recommend the "half mile" statement be included within the
Applicability section of this Standard as it stated in FAC-003-X.
Yes
Yes
Yes
Although the NSRF agrees with the 1/2 mile criteria (see question 1); we believe the drafting team
will have to develop additional justification for this criteria given FERC's recent orders, RC11-1 and
RC11-2 (see question 6 for full FERC Order details). In these orders FERC "implies" that if the
GO/GOP is responsible for a breaker operated at 100kV or higher the entity should be required to
register as a TOP/TO. Therefore it appears FERC would not be inclined to provide any leeway based
on distance from the substation. The SDT should note that the FERC Order points to this Project to
"address matters involving reliability obligations at the interface of the transmission grid", which is
foot note 58.
Yes
Yes
In FERC order "Denying Appeals of Electric Reliability Organization Registration Determinations" dated
June 16, 2011 (RC11-1 and RC11-2) FERC explicitly stated compliance GAPs existed with the
following standards at a minimum: • FAC-011, Requirements R2, R2.1, R2.2. • PRC-001-1,
Requirements R2, R2.2, R4; • PRC-004-1 Requirement R1; • TOP-004-2, Requirements R6, R6.1,
R6.2, R6.3, R6.4; • PER-003-1, Requirements R1, R1.1, R1.2; • FAC-003-1, Requirements R1, R2; •
TOP-001, Requirement R1 and • FAC-014-2, Requirement R2. When a GO/GOP owns transmission
equipment but is not registered as a TO or TOP. The drafting team should explicitly address each of
these the above requirements.
No
Individual
Jody Nelson
Georgia Transmission Corporation
Yes
We commend the drafting team for their efforts to address gaps in Facility Connection Requirements.
We believe that the requirements under R3 should be limited to Generator owned equipment to avoid
duplication of efforts. A Generator Owner receiving an interconnection request is required to submit
an interconnection request to the Transmission Owner which in turn would study the impact of such a
request on the Transmission System. Therefore there is no gap as far as the Integrated Transmission
System that the third party is interconnecting to through the Generator Owner. However, Generator
Owners are responsible for verifying that their equipment is capable of accommodating the
interconnection request.
Yes
Yes
Yes
No
No
Individual
Bill Rees
BGE
Yes
This change closes the gap in areas not already covered under FAC-003-1 in a continuous
improvement effort to ensure vegetation-related transmission reliability for applicable lines.
Yes
This requirement is consistent with the initial time frame when FAC-003-1 was first implemented.
Yes
As noted in Question-1 above.
Yes
1/2 mile is a distance that can generally be viewed from one location, e.g. the switchyard, and can be
construed to present minimal risk since switchyards have a reasonably frequent personnel presence
that could be expected to notice vegetation issues in the <1/2 mile area.
Yes
No comment.
No
No comment.
No
No comment.
Group
Electric Market Policy
Connie Lowe
Yes
Yes
Yes
Yes
Yes
No
No
Group
SERC Planning Standards Subcommittee
Charles W. Long
Yes
Yes
Yes
Yes
However, we are concerned that there may be a reliability gap for locations where there is not a halfmile line-of-sight from the generation switchyard.
Yes
No
No
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
These comments supersede the previous comments submitted by Arizona Public Service Company on
July 7, 2011.
Yes
Yes
No
The generator should be responsible no matter the length from fence area to the point of
interconnection.
No
The generator should be able to be in compliance within one year since the distance of line miles is
small.
No
No
Individual
John Bee
Exelom
No
Exelon does not agree that this standard should be broadly applied to a GO. GOs who do not own a
switchyard and whose point of interconnection is a disconnect switch associated with the generator
leads prior to the switchyard should be excluded from this standard. If a group of GOs share a
generator tie line, then the associated Interconnect Agreement that each of the GO has with the
applicable TO and/or TOP should address how these shared connections will effect the system. GOs
may not have the resources or expertise to conduct the required interconnect studies to meet this
standard
Yes
Yes
Yes
No
Yes
FAC-001 1. Exelon has generating stations that have the Main Power Transformer (MPT) disconnect as
the point of demarcation. The station owns the short leads from the MPT disconnect back to the
generator and the applicable TO owns from the MPT disconnect up to and including the switchyard. It
is not practical for another entity to request to interconnect to the MPT disconnect nor should it be
allowed. The SDT should consider verbiage to the standard that does not allow requests to
interconnect to a MPT disconnect. 2. Exelon is having difficulty determining how this standard would
apply to GOs and how GOs would implement the standard; suggest that examples be provided in an
implementation document specifically showing where and how this standard would apply.
Group
Imperial Irrigation District (IID)
Jesus Sammy Alcaraz
Yes
Yes
Yes
Yes
Yes
No
No
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
Yes
However, there may need to be a variance for ERCOT because the Power Generating Companies in
ERCOT are not allowed to own transmission assets.
No
: As drafted, the document still refers to generation interconnection lines as transmission lines in
critical places. We understand that the SDT has taken significant steps to minimize this in both FAC001 and FAC-003 and has had discussions with NERC about not registering GOs as TOs; however, this
lack of distinction between high voltage generation interconnection lines and actual transmission lines
still presents a difficult situation for Generations Owners and a source of contention with Reliability
Entities. This could be resolved somewhat by using the non-defined term “generation interconnection
lines” in place of “transmission lines” in, for example, section 4.3.1. Since the term “transmission line”
is also undefined, this would seem to be a reasonable approach.
No
Ingleside Cogeneration LP believes there should be a relaxation in the vegetation management
requirements for those interconnections which only serve as a radial link to the BES. Although we fully
understand the importance of keeping vegetation away from high voltage lines, the one year period is
much too frequent in our generator locations. The added documentation and other expenses simply
do not justify the non-existent gain in reliability when vegetation in a locale (e.g.; desert) never
reaches five feet above the ground. Consider limiting this exception to units below a certain MVA
rating that are not critical to the BES – perhaps coupled with evidence that vegetative intrusions are
highly unlikely.
No
The SDT needs to clarify that the one-half mile distance is measured from the property line of the
Generation Owner, i.e., an interconnection line that is in a ROW. In addition, the half mile qualifier
makes sense only for those interconnections into critical generation facilities. See our response under
Question #3.
No
The two year compliance time frame makes sense only for those GOs who own interconnections into
critical generation facilities. See our response under Question #3.
No
Yes
There is a fundamental issue related to the interconnection of generation and distribution facilities
into the transmission grid. There is a myriad of complex architectures which make the designation of
ownership and operational responsibilities unclear in both cases. Both this team’s efforts and those by
the project team redefining the extent of the BES have run into this issue. Ingleside Cogeneration LP
recognizes that the effort to properly assign reliability responsibilities in these gray-area connections
is difficult. However, pushing the issue back to the GO/GOP by looking for them to jointly determine
responsibilities with adjacent entities will create every conceivable arrangement possible. It seems
like it should be possible to address a handful of common interconnection configurations at the start.
As knowledge builds, perhaps other architectures could be added. This seems to be the direction that
the project team redefining the extent of the BES is heading. Lastly, we need some assurance that
regulators will work with us as we go down this path. Right now, the feeling is that they will continue
to use forced registrations as a hammer – which may render moot this team’s efforts anyways.
Group
LG&E and KU Energy
Brent Ingebrigtson
Yes
Although the “one half mile” is much clearer than “two spans”, what is the rationale for choosing ½
mile as opposed to another length such as 1 or 2 miles?
Individual
Dale Fredrickson
Wisconsin Electric
No
In addition to the "greater than one-half mile" criteria, we maintain there should also be an exclusion
for lines up to one mile in length which are entirely on the Generator Owner's property.
Yes
No
No
Individual
Keith Morisette
Tacoma Power
Yes
Yes
Yes
Tacoma Power suggests that three standards be reconsidered for inclusion in this Project, to include
the Generator Owner and/or Operator: EOP-005, more directly responsible for participation in
restoration plans; PER-002, responsible for training; and VAR-001.
Individual
Joe Petaski
Manitoba Hydro
No
The Applicable Entities now include a Generator Owner that meets the following condition: ‘Generator
Owner with an executed Agreement to evaluate the reliability impact of interconnecting another
Facility to its existing generation Facility’ A Generator Owner should not have such power. In many
instances Generator Owners do not have the models or expertise to perform interconnection studies
to determine if there is an impact on the Transmission Network. All interconnection requests should
be implemented by the Transmission Owner (TO) regardless if the interconnection point is within a
Generation Owner facility or End-User facility. The TO is in the best position to set unbiased
connection requirements to ensure the reliability of the BES is maintained. If a mechanism is created
to allow interconnection to a BES line owned by Generator Owner, then it is essential for this
Generator Owner providing this interconnection service to be a TO to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is maintained. The drafting
team should demonstrate where this situation is occurring. If the redline changes are implemented,
could Generator Owner #1 permit Generator Owner #2 to interconnect one of their generators within
Generator Owner #1’s Facility? Would Generator Owner #2 then need to have an executed
Agreement to permit further generator interconnection? From a Transmission Owner viewpoint, it is
tough enough to coordinate generator connection queues among adjacent TOs. Having to coordinate
with Generator Owners as well would greatly increase the complexity of coordination.
No
See question #1 comments. We do not support changing the applicability of FAC-001-1 to include
Generator Owners ‘with an executed Agreement’ or Generator Owners that own BES transmission.
No
The direction of the background resource document gives special treatment to the Generator Owner
in that it allows the Generator Owner TO status for a couple of standards (FAC-001 and FAC-003), but
exempts the Generator Owner from many of the standards applicable to a TO. The NERC Functional
Model defines the various functional entities. If a Generator Owner wants to be a TO, all the
Requirements applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions.
Yes
The direction of the background resource document gives special treatment to the Generator Owner
in that it allows the Generator Owner TO status for a couple of standards (FAC-001 and FAC-003), but
exempts the Generator Owner from many of the standards applicable to a TO. A Generator Owner
that owns BES transmission should be held accountable for the specific Requirements and Reliability
Standards applicable to the TO and Transmission Operator functions. If no other entity assumes
accountability for these specific Requirements and Reliability Standards on the Generator Owner BES
transmission (for example system operation, protection and communication), there will be a reliability
gap. Improper operation, coordination and protection of the Generator Owner BES transmission could
have an impact on reliability.
Individual
Greg Rowland
Duke Energy
Yes
Yes
Yes
Yes
Yes
No
No
Group
Public Service Enterprise Group
John Seelke
No
The language in R2 needs to be clarified with regards to the term “its existing generation Facility.”
The interconnection leads are considered part of the “existing generation Facility,” but so are the
generator, generator step-up transformer and other equipment associated with the generator. The
project Background Resource Document (p.2) makes it clear that the interconnection to an existing
generator facility is contemplated to be to the “existing interconnecting Facility that is owned by a
generator” – i.e., the generator’s interconnection leads. We propose that the term “its existing
generation Facility” be replaced with “the Generator Owner’s existing interconnecting transmission
Facility.”
Yes
No
FAC-003-X and FAC-003-3 both have similar “one half mile” language, the starting point for the one
half mile is vague. In FAC-003-X, the language in 4.3.1 reads “Generator Owner that owns an
overhead Facility that extends greater than one half mile beyond the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection with the Transmission
system and …” While we support the one half mile language, there are three possible staring points
for the measurement of the one half mile: beyond the fenced area of (i) the switchyard, (ii) the
generating station, or (iii) the generation substation. While a GO’s fencing policy may differ between
generation stations, the requirement to implement vegetation management should be clear. For
clarity, while we believe that the language should retain flexibility with regards to “fencing” by the
Generator Owner, it should be clear that the Generation Owner determines the starting point. Second,
a Generator Owner’s overhead Facility that is within the fence should explicitly not be applicable to
the standard. Finally, we believe the language that refers to the “interconnection with the
Transmission system” should be changed to “interconnection with a Transmission Owner’s Facility.
The reason is that the term “Transmission” which is defined in the NERC Glossary could be construed
to include all of a Generator Owner’s interconnection leads. (The definition is excerpted from the
Glossary in our response to question 7) Therefore, we suggest that the language in 4.3.1 be modified
as follows to make all of these points clear: A Generator Owner that owns an overhead Facility that
extends greater than one half mile beyond the fenced area of either the generator switchyard,
generating station or generating substation (as specified by the Generation Owner) up to the point of
interconnection with a Transmission Owner’s Facility and is operated 200 kV and above and any lower
voltage lines designated by the RE as critical to the reliability of the electric system within the region
is applicable to this standard.”
Yes
Yes
Yes
FERC’s Cedar Creek and Milford order (issued on June 16, 2011 and that is posted at
http://www.nerc.com/files/Order_Denying_Appeals_RC11-1_RC11-2_20110616.pdf) listed several
standards (in Paragraphs 71 and 87) that should be applicable to Cedar Creek and Milford,
respectively. Because of this order, the drafting team should examine the listed standards and
determine whether they are or are not applicable to Generator Owners or Generator Operators that
own and are responsible for the operation of an overhead Facility. We emphasize that our
recommendation takes no position on any legal issues regarding the referenced order.
Yes
While we generally agree with the drafting team’s modifications to these standards, the team’s
approach may not directly resolve the fundamental registration issue regarding a Generation Owner
that only owns non-integrated interconnection transmission facilities. The non-integrated
interconnection transmission facilities owned by a GO are part of the Bulk Electric System (BES)
because they are part of BES generation facilities. The ownership of these non-integrated facilities
should not require a GO to also register as a Transmission Owner. The draft team has proposed
modifying two FAC standards that would apply to such GO-owned interconnection transmission
facilities. These GO-owned interconnection transmission facilities are not, however, “integrated”
transmission facilities, as the drafting team correctly points out in its background resource document.
A proposed solution to the Generation Owner registration issue is discussed below. NERC’s Rules of
Procedure (ROP) require entities to be registered in accordance with the definitions in the NERC
Glossary of Terms Used in Reliability Standards (Glossary) and in accordance with the NERC
Statement of Compliance Registry Criteria document. The Glossary has these definitions: •
Generation Owner – Entity that owns and maintains generating units. • Transmission Owner – The
entity that owns and maintains transmission facilities. • Facility – A set of electrical equipment that
operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator,
transformer, etc.) • Transmission – An interconnected group of lines and associated equipment for
the movement or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems. • Transmission Service
– Services provided to the Transmission Customer by the Transmission Service Provider to move
energy from a Point of Receipt to a Point of Delivery The drafting team should create a new definition
for the term “integrated transmission facilities” and include this new definition in the Glossary. This
definition should then be use to modify the definition of Generation Owner so that registration will be
clear. While the team chose not to create any new definitions, we believe the registration issue cannot
be resolved without modifying the definition of “Generation Owner The following definition is proposed
for Integrated Transmission Facilities in the NERC Glossary: • Integrated Transmission Facilities (ITF)
– ITF are the Facilities that are a subpart of Transmission system that are capable of carrying the
flows from multiple generator plants at different points of interconnection for delivery to customers or
to other electric systems. This proposed ITF definition builds upon FERC precedent in the Open Access
Transmission Tariff (OATT) area. FERC has recognized that facilities that can carry flows from multiple
supply points and deliver that power to either customers or other electric systems are proper facilities
to include in an OATT and define the “Transmission System” for OATT purposes. The term
“Transmission System” is an OATT-defined term that means “The facilities owned, controlled or
operated by the Transmission Provider that are used to provide transmission service under Part II
[Point-to-Point Transmission Service] and Part III [Network Integrated Transmission Service] of the
Tariff.” Under FERC’s precedent, facilities such as generator step-up transformers and generator
interconnecting transmission facilities have been excluded from the OATT; i.e., they are not facilities
that provide Transmission Service because they cannot carry the flows from multiple supply points for
delivery to customers or other electric system – their only use is to the Generation Owner. They
perform two functions for a GO: 1. They deliver power from the GO’s generators at a site to the
OATT-defined Transmission System, and 2. They deliver off-site power from the OATT-defined
Transmission System to the generators at a site when the generators at a site are not operating.
While building on FERC OATT precedent, the proposed definition of “Integrated Transmission
Facilities” does not require an applicable Transmission Service tariff to identify those facilities.
Integrated Transmission Facilities are simply defined as those that capable of carrying flows from
multiple supply points for delivery to customers or to other electric systems. Using the ITF definition,
the definition of Generation Owner could be modified as follows: • Generation Owner – Entity that
owns and maintains generating units but which does not own or maintain Integrated Transmission
Facilities.
Group
SPP Reliability Standards Development Team
Jonathan Hayes
No
We are concerned that some of the language is ambiguous. We would like to be clear that placing
new requirements on Generator Owners that are already in place and have been in place under FERC
policy is inaccurate. We want to make sure that regardless of what the generator tie line is classified
as, that a valid interconnection would go through the Generator Interconnection process under its
applicable tariff. Format error in 2.4.1 should read 4.2.1 in applicability. We would like to see more
definition in applicability section 4.2. How does the Generator Owner get involved in this process? The
VRF for R4 is listed as a medium and appears to us as an administrative requirement. We would
recommend that the VRF be changed to low. The moderate and high VSL for R1 seems to be
duplicative. We would recommend taking a second look and would recommend that the high should
be that “if you failed to do two of the following”. We would recommend that the VSL on R4 read: “The
responsible entity failed to make the requirements available within 30 business days after a request.”
Yes
No
In both FAC003-3 and FAC003-X it lists “greater than one half mile cutoff”. We would recommend
that the distance cutoff be removed. We feel that overhead Facilities shouldn’t be treated any
differently than any other. Also we would like to see these two sections in both standard proposals
reflect similar language for 4.3.1.
No
See comment above. We feel like there is no need for using a distance exclusion.
Yes
No
No
Individual
Amir Hammad
Constellation Power Generation
Yes
Yes
Yes
Yes
Yes
No
Yes
Constellation appreciates and supports the work of the standard drafting team. We recognize the
significant time invested by technical experts from industry to consider the appropriate application of
reliability standards to address concerns raised about coverage of transmission at the generator
interface. The recent FERC Order concerning Cedar Creek and Milford wind suggested that the list of
applicable standards needing revision should go beyond FAC-001 and FAC-003. We appreciate the
discussion and concerns raised by FERC in the order; however, the discussion is limited by failing to
consider these issues in light of the full package of existing standards. Below is a look at the FERC
suggested standards and how they intersect with other standards: • PRC-001-1, Requirements R2,
R2.2, R4 FERC expressed concern that certain protection system components may not be well
coordinated with the RC. However, the same standard (PRC-1) addresses this issue by requiring all
GOs to ensure coordination of their protection system with interconnected parties. Further, FAC-002
requires that all new facilities undergo reviews by the TOP, BA, etc. • PRC-004-1 Requirement R1
FERC expressed concern that certain protection system components may not be analyzed for
misoperations. However, the same standard (PRC-4) addresses this issue by requiring all GOs to
ensure that they analyze all misoperations on their protection system which would include the
protection of the tie line. • TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4; FERC expressed
concern that coordination may be lacking between a GO and a TO with regards to the generator tie
line. However, TOP standards applicable to GOs address this issue by requiring all GOs to coordinate
all maintenance and emergency outages (both forced and planned) with all applicable interconnected
parties. Further, all ISO procedures require the same of GOs. • PER-003-1, Requirements R1, R1.1,
R1.2; FERC expressed concern that certain generator operators are responsible for the real time
operation of the interconnected BES without being NERC certified operators, potentially causing a
reliability gap. Generator Operators do not monitor and control the BES, they control and monitor
generators that it operates and relays information to other operating entities. Therefore, NERC
certification is not required. • FAC-003-1, Requirements R1, R2; FERC and the drafting team seem
aligned in the need to revise this standard and the revision proposal includes such a revision. • TOP001, Requirement R1 FERC expressed concern that certain tie lines may not be required to operate in
such a way as to alleviate operational emergencies. However, IRO and TOP standards applicable to
GOs address this issue by requiring all GOs to operate as directed by their TOP, BA, or RC as directed
and must render emergency assistance. • FAC-014-2, Requirement R2. FERC expressed concern that
certain tie lines may have a rating based on a methodology that may not be consistent with the
methodology used by the RC. However, standards FAC-8 and FAC-9 address this issue by requiring all
GOs to develop a methodology to rate all equipment, and that the RC has the authority to challenge
the GO on that methodology. The onus is on the GO to either change their methodology and rating
accordingly, or provide a technical justification as to why they cannot adopt the changes. Further, a
generator will never be limited by its tie line, as a generator’s profits are directly tied to its output.
Therefore no generator would limit its facility to the equipment that is delivering that output.
Group
Westar Energy
Bo Jones
No
We suggest the VRF for R4 be changed from medium to low, as it is administrative in nature. We
recommend the high VSL for R1 read, “The Transmission Owner failed to do two of the following.”
Yes
No
The language in the applicability section 4.3.1 in both FAC-003-3 and FAC-003-X states “extends
greater than one half mile beyond…” We propose that the SDT consider removing the distance
exclusion to be consistent with language for Transmission Owner Facilities and treat all overhead
facilities the same.
No
Yes
No
No
Individual
Kirit Shah
Ameren
Yes
Yes
Yes
No
(1)We do not agree there should be a ½ mile exemption. On what legitimate basis could we say the
first ½ mile is not important? (2) There may be different usage of the term "point of interconnection"
in the industry. We suggest the SDT to consider proposing a formal definition of this term.
Yes
No
No
Individual
Rex Roehl
Indeck Energy Services
Yes
Yes
No
4.3.1.3 is a regional variation. The ROP doesn't permit members of one region to vote on regional
requirements for another region. A separate regional standard will be required.
Yes
Yes
No
Individual
Chad Bowman
CHPD
Yes
Yes
Yes
Yes
Yes
No
No
Individual
Andrew Z Pusztai
American Transmission Company
No
R1 wording in this draft only requires having published Facility connection requirements, but speaks
nothing of specific required content of this published document. (R1) VSLs specifically reference R1. If
VSLs continue to include assessment of how many R3 (R2 in present standard) requirements are met,
a TO potentially has a redundant obligation under two separate requirements. R1 and R3 do not read
in a manner consistent with (R1) VSLs. Since R2 only applies to Generator Owners, the (R2) VSL
should use “Generator Owner” in place of “responsible entity.”
No
ATC does not support the changes for FAC-003-X, however, ATC does support FAC-003-3. FAC-003-X
Concerns The VRF and VSL tables do not correlate to the original FAC-003-1 levels of non-compliance
section D.2.ATC believes that section D.2 should be rewritten to align with the already approved FAC003-1. FAC-003-X Corrections- Applicability Section 4.3.1, sentence 3 – Transmission should not be
capitalized. FAC-003-3 - No Concerns
Group
Southern Company
Antonio Grayson
No
Southern does not think that the revision to FAC-001-1 is necessary. A Generator Owner (GO) cannot
assess reliability impacts to the Bulk Electric System (BES) and determine acceptability without
support and involvement of the applicable owner and operator of the Transmission System. A
generator tie-line does not equate to a Transmission System. A GO must already adhere to a TO’s
Facility connection requirements whether the GO wants to connect additional facilities or a third
parties facilities to its own interconnection Facilities. Stated another way, the GO does not need
Facility Connection requirements to govern how multiple units are tied to a collector bus so why are
they needed for a third party to connect to an existing tie-line? In either case it is the interconnected
TO that has connection requirements that must be fulfilled. The GO’s Interconnection Agreement
would prohibit it from connecting additional facilities without a new application for Interconnection
Service with its interconnected Transmission Provider. A GO should not need to develop “connection
requirements” unless it is in the business of owning and operating facilities independently of its
interconnected Transmission Provider. We do not believe a reliability gap exists in FAC-001-1 because
the requestor for interconnecting another Facility to an existing generation Facility must coordinate
with the applicable TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable
facility connection and performance requirements. If and when there is an agreement in place for a
third party to connect to a generator tie-line then the tie-line would become part of the integrated
system and its purpose and the owner’s function would likely warrant registration as a TO/TOP and
FAC-001 would then apply. The following excerpt from the 2010-07 Background Resource Document
acknowledges that this may be necessary: “The drafting team also acknowledges that, if another
party interconnects to a Facility owned by a Generator Owner, there may be the need to address MOD
or TPL standards. However, the drafting team believes that this, too, is best handled through specific
evaluation, perhaps accompanied by changes to the compliance registry. Entities that face this kind of
scenario may also meet criteria applicable to other registrations such as Transmission Service
Provider or Transmission Planner.” B. If the Project 2010-07 Drafting Team decides to continue
revising FAC-001-1, there are jurisdictional, interconnection policy and open access transmission tariff
issues that will need to be considered. (1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access transmission tariff
(OATT), a GO should not be required to comply with FAC-001-1 until that GO’s generating Facility
reaches commercial operation. (a) Jurisdiction under FPA Section 215. First, it is not clear that NERC
or FERC has jurisdiction under FPA Section 215 to require generation facilities that have not actually
reached commercial operation to be subject to reliability standards. Section 215(a)(2) of the FPA
defines the “Electric Reliability Organization” as “the organization certified by the Commission … the
purpose of which is to establish and enforce reliability standards for the bulk-power system, subject
to Commission review.” Further, (a)(3) provides that “The term ‘reliability standard’ means a
requirement, approved by the Commission under this section, to provide for reliable operation of the
bulk-power system. The term includes requirements for the operation of existing bulk-power system
facilities … the design of planned additions or modifications to such facilities to the extent necessary
to provide for reliable operation of the bulk-power system ….” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system facilities (i.e.,
facilities that have reached “commercial operation”) and for the design of planned additions or
modifications. It is logical to interpret the phrase “design of new facilities” as meaning that new
facilities must be designed to comply with existing reliability standards. However, it is not clear that
this provision should be interpreted as requiring that a generating facility that has not yet reached
commercial operation should be subject to reliability standards (including audit and penalties).
Therefore, the GO with the existing generation facilities should not be required to incorporate the
proposed generation facility into its Facility connection requirements before the proposed generation
facility is subject to NERC or FERC jurisdiction. (b) FERC’s interconnection policy. In addition, the
revised FAC-001 would appear to place restrictions on interconnection customers in contravention of
Order Nos. 2003 and 2006 (Standard Large and Small Interconnection Procedures and Agreements).
FERC was very concerned about the ability of interconnection customers to interconnect their
generating facilities and gave them a fair amount of flexibility. However, this revised FAC-001 would
appear to restrict some of this flexibility. (i) Order No. 2003 gives the interconnection customer the
ability to terminate a proposed interconnection on ninety days notice. Therefore, the interconnection
customer is not required to build the facility. However, this revised FAC-001 appears to assume that
the interconnection customer does not have this flexibility. What if the interconnection customer (the
GO building a new generator on its site or the third party building a new generation facility) decides to
terminate the Large Generator Interconnection Agreement (LGIA) or not proceed with the generation
facility? In such event, the GO may be required to revert to its previous Facility connection
requirements in order to accommodate the original configuration. (ii) The LGIA permits modifications
to the proposed interconnection. How would this affect the Facility connection requirements? How
long would the GO have to revise its Facility connection requirements? In the event that there is a
single modification, or perhaps multiple modifications, how does the GO stay in compliance with this
standard? (iii) FAC-001-1, R4 provides that each GO with Facility connection requirements and each
TO shall maintain Facility connection requirements and make documentation of these requirements
available to users of the Transmission System upon request. However, Large Generator
Interconnection Procedures (LGIP), Section 3.4 requires the posting of certain interconnection
information but the identity of the interconnection customer is not to be disclosed (unless it is an
Affiliate). Requirement R4 would appear to potentially require disclosure of information and (more
importantly) of the interconnection customer's identity in contravention of the requirements in Order
No. 2003 and the LGIP. (c) OATT requirements. The definition of “applicable Generator Owner”
(Section 4.2.1) and Requirement R2 provide that the GO will have an executed Agreement to
evaluate the impact of interconnecting a new facility to the GO’s existing generation facility. This
statement is ambiguous. This statement could be understood to mean that the GO of the existing
generation Facility will enter into an Agreement with the GO proposing to interconnect and the
existing GO will evaluate the impact of the proposed interconnection. However, requests to
interconnect new generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the new facility.
Thus, the language in FAC-001-1 would need to be revised to clarify that the owner of the new facility
will need to interconnect under the OATT of an appropriate Transmission Provider (i.e., the
Transmission Provider to which the existing GO is interconnected, not with the existing GO).
Therefore, the owner of the new facility will most likely be the entity with the executed Agreement
(with the Transmission Provider). Another consideration is that the existing GO could be developing a
merchant transmission line. In that case, the existing GO would need to evaluate whether it needs
have its own OATT and OASIS. In that case, the new generator owner would be interconnecting to the
existing GO. However, the existing GO’s line would not be a generator tie-line. This issue is not clear
from the draft standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES reliability…” (b) The
numbering for “Applicable Generator Owner” should be 4.2.1 instead of 2.4.1. (c) It is not clear who
may request to interconnect to the Generator Owners’ facility. The Background Resource document
states that “[b]ecause Generator Owners may be requested to allow interconnection to their Facilities”
– this would imply that a third party may request interconnection to the Generator Owner’s Facilities.
However, draft FAC-001-1 discusses “interconnecting another Facility to its existing generation
Facility.” This issue needs to be clarified. Is it simply when a Generator Owner proposes to add a new
facility to its existing facility or does it also include a third party request to interconnect to the
Generator Owner facilities? (d) R4 should be revised to delete the requirement to maintain the Facility
connection requirements because this is redundant to language in R1 (and R2, which we believe is not
needed). In addition, R4 should be revised to state, “…on requests within five (5) business days”
since the time requirement is essential for measurement of non-compliance as indicated by the VSLs.
(e) The Severe VSL for R3 should be revised to delete the second portion which states, “The
responsible entity does not have Facility connection requirements.” This non-compliance would be
covered by the first portion of the two-part OR requirement (…four or more…). It is also covered by
the Severe VSL of R1. (3) Effect of the proposed revisions to FAC-001-1 on FAC-002-1. (a) As
drafted, there are scenarios under which a new GO may attempt to interconnect to an existing GO
even though, as explained above, the interconnection should actually be done to the appropriate
Transmission Provider. If the appropriate Transmission Provider is not included in the evaluation of
the interconnection various types of harm may occur. In such event, the TPs and PAs should be
indemnified from any liability with respect to performance of the evaluations required by FAC-002. (b)
FAC-001 and FAC-002 should be revised to be clear that the existing GO and any new GOs must
coordinate any interconnection with the appropriate Transmission Provider, TP and PA.
Yes
However, we do not believe it is necessary to require a GO to have Facility connection requirements
as we discuss in our response to Question 1.
No
(1) We question whether R1 of FAC-003-3 would ever apply to a GO who owns transmission
interconnection equipment. Can the SDT provide an example or two in the Guideline and Technical
Basis section of the standard? (2) We recommend rearranging the language in R5 of FAC-003-3 to
state, “The applicable Transmission Owner or applicable Generator Owner shall take corrective action
to ensure continued vegetation management to prevent encroachments when…” This places the
“shall” at the beginning of the requirement which is clearer and consistent with the structure of the
other requirements. (3) We question why there are no VSLs assigned to R4. Should there be? What
are the consequences if a Regional Entity does not comply? (4) There does not appear to be any
coordination with the Vegetation Management Standard Drafting Team (VMSDT) concerning proposed
modifications to the standard. The VMSDT should be consulted.
No
We agree with a one-half mile line as being “within the Generator Owner’s line of sight and could be
visually monitored for vegetation conditions on a routine basis.” However, we suggest that some
generation interconnection Facilities greater than ½ mile in length could also fall within the GO’s line
of sight or be constructed such that they should be considered for exemption. Thus, the Task Force
should consider including exclusions for longer generator tie lines if the GO can provide sufficient
justification. Examples of justifications could include (1) a clear line of sight, (2) pavement, gravel, or
other non-vegetation covered path, or (3) routine monitoring is performed from a roadway parallel to
the line, etc. Do not obviate any other transmission requirements such as the following (which are
incorporate into the draft standard): i. Operated at 200kV or higher; or ii. Operated below 200kV and
included in IROL; or iii. Operated below 200kV and inclusion in a Major WECC Transfer Path
Yes
Yes
Please see our Comments in response to Question 7.
Yes
(1) The SDT needs to review the June 16, 2011 FERC Order on Cedar Creek and Milford and factor
this into the equation. The FERC Order concludes that the Cedar Creek and Milford entities must
register as a TO and TOP. In addition to FAC-003, the Cedar Creek and Milford order lists the
following standards and requirements that apply to these entities as a TO/TOP: • PER-003-1, R1,
R1.1, R1.2 (requiring NERC-certified transmission operators); • PRC-001-1, R2, R2.2, R4, R6
(notification of relay or equipment failures); • PRC-004-1, R1 (analyzing protection system
misoperations); • FAC-014-2, R2 (establishment of system operating limits); • TOP-001, R1
(authority to take actions to alleviate operating emergencies); • TOP-004-2, R6, R6.1, R6.2, R6.3,
R6.4 (establishment of formal policies to address voltage levels, planned outages, switching,
Interconnection Reliability Operating Limits, and System Operating Limits). The SDT needs to address
these specific requirements in sufficient detail by either revising the Project 2010-07 Background
Resource Document or proposing revisions to these standards to address any reliability gaps. For
example, we recommend, as a minimum, that the Background Resource Document discussion under
PRC-001-1 be revised to state (underlined text added), “Generator Operators and the scope of
protection equipment for generation interconnection Facilities are already appropriately accounted for
in this standard in requirements R1, R2, R3, and R5.” Please note that this statement, even with our
proposed revision, conflicts with the FERC Order on Cedar Creek and Milford, Paragraphs 64, 65, and
78 where FERC states that Cedar Creek and Milford must register as a TO and TOP to ensure the
protection system coordination requirements in R2 and R4 of PRC-001 are met. Thus, the discussion
for PRC-001-1 in the Project 2010-07 Background Resource Document needs additional language to
demonstrate adequacy of the GO requirements in order to prevent GOs that own generation
interconnection Facilities from having to register as a TO and TOP. (2) In addition, we believe the SDT
should add supporting discussion to the Background Resource Document to explain why the following
standards adequately cover GO/GOP requirements at the Transmission Interface: PRC-004-2, PRC005-1, PRC-023-1. For example, the Background Resource Document could state that PRC-023-1
Section A.4 Applicability already includes, “4.2. Generator Owners with load-responsive phase
protection systems as described in Attachment A, applied to facilities defined in 4.1.1 through 4.1.4.”
(3) Furthermore, FERC’s analysis in the Cedar Creek and Milford order suggests that reliability gaps
will occur if certain entities are not registered as TO/TOP. The GRTI SAR DT should assess why its
findings are different from the Commission’s findings. By way of background, the GRTI SAR DT
provides that its own assessment of the GOTO Ad Hoc Group Final Report concludes with a belief that
there are only two standards requiring modifications to address reliability gaps – FAC-001 and FAC003 (Background Resource Document, page 3). FERC will most likely require that NERC clearly
demonstrate and provide technical support for the position that GO’s only need to comply with FAC001 and FAC-003 and not the other standards noted by FERC. The Background Resource Document
does not appear to provide adequate technical support for the GRTI SAR DT position. Therefore, the
GRTI SAR DT should develop that technical support in preparation for the filing of these revised
standards at FERC.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
Yes
Yes
We generally agree with the proposed distance. However, we suggest that in Applicability Section
4.3.1 of the two draft standards, an equivalent kilometer value be inserted after the “one half mile”.
Yes
No
No
Individual
Doug Hohlbaugh
FirstEnergy Corp
Yes
FirstEnergy (FE) appreciates the drafting team's careful consideration of the comments made by FE
during the most recent informal comment peroid. The changes made to FAC-001 alleviate FE's prior
concern related to a Generator Owner needing to maintain and publish a Facility Connection
requirements document regarding facilities which are not yet subject to Open Access provisions. FE
supports the team's changes to FAC-001-1 and the concept that a connection requirement document
would be required upon the initial or 1st time a Generator Owner executes an Agreement to perform
the reliability assessment required in FAC-002-1.
Yes
The one year lead time is sufficient lead-time to notice the GOs of new expectations required under
FAC-001-1.
Yes
Yes
Yes
No
Yes
The June 16, 2011 FERC Order denying the appeals of two wind generating facilities—Cedar Creek
and Milford – of the NERC determinations that Cedar Creek and Milford must each be registered as a
transmission owner and transmission operator on the NERC Compliance Registry complicates the GOTO drafting team’s work. However, the issues may be distinct and different in the end. The existing
GO-TO team’s work product defines new reliability expectations for a generator owner regardless of
whether or not the same entity is also being required to have a TO-TOP “light” compliance
registration. In the Order, FERC describes what it believes are an appropriate limited set of TO-TOP
requirements when a TO-TOP “light” registrations is deemed warranted for a traditional generation
owner. The drafting team should describe what, if any, impact the FERC June 16 Order is having on
its work scope. One minor comment for the background resource document. On page one, the last
sentence of the 1st paragraph which currently reads “ … appropriate level of reliability for the BES.”
Consider changing to read “ … Adequate Level of Reliability for the BES.” And, include a footnote
directing the reader to NERC’s definition/paper describing ALR. The later references to “adequate level
of reliability” within the document (i.e. page 2, 2nd paragraph could then be reduced to the acronym
ALR.
Individual
Sandy O'Connor
TransAlta Centralia Generation LLC
Yes
Yes
Yes
Yes
Yes
No
No
TransAlta Centralia Generation LLC (TransAlta) supports the recommendations put forward by the
Project 2010-07 drafting team. The implementation of these recommendations will provide for much
needed certainty for owners and operators of generation facilities.
Group
PPL Supply Group
Annette Bannon
No
A Generator Owner subject to the proposed standard (i.e., with an executed Agreement to evaluate
the reliability impact of interconnecting another Facility to its existing generation Facility) should only
be responsible for evaluating the impact of such interconnection on its facilities. Generation Owners
should have no responsibility for evaluating impacts on interconnected or adjacent Transmsision
Owner systems. GOs do not have staff trained or tools available to perform the studies necessary to
evaluate reliability impacts of such interconnections on Transmission Owner systems which can exend
geographically far beyond the POI. The SDT should clarify that Transmission Owners are solely
responsible for evaluating and addressing any impacts on their systems.
No
It may take longer since very few (if any) GOs are prepared to perform this type of work.
No
Version 3 (based on V2): Third Effective date appears to contain a typographical error. Version X
(based on V1): Same as Version 3 comments. Please consider streamlining the section Background
(Version 3).
No
Version 3 (based on V2): Comments: Although the “one half mile” is much clearer than “two spans”,
what is the rationale for choosing ½ mile as opposed to another length such as 1 or 2 miles? Version
X (based on V1): Same as Version 3 comments
Yes
Yes
Group
ACES Power Members
Jason Marshall
No
We support the concept of modifying FAC-001-1 to include Generation Owners that own transmission
lines that interconnect them to the BES for the purpose of eliminating the need to register Generation
Owners as Transmission Owners. However, there are serious issues with the implementation of the
FAC-001-1. The changes conflict with the tariff process of many established markets as well as the
FERC pro forma tariff. Requests to interconnect are generally governed by tariffs. The request will be
submitted to the transmission provider established by the tariff. The transmission provider will then
perform the necessary studies such as system impact or feasibility studies to determine any
necessary upgrades through its long-term planning function. After the completion of these studies or
in parallel with them, the Transmission Owner (or Generation Owner that owns transmission) will
perform the facility connection study. This may or may not require an additional contract as it may be
governed completely under the tariff or may be covered under a blanket agreement in an organized
market. The language referring to the executed Agreement in the standard should be dropped as it is
confusing and may not cover many situations. Rather, the standard should apply to the Generation
Owner that owns Transmission and is not registered as Transmission Owner. R2 should be modified
such as the Generation Owner that owns Transmission is required to create facility connection
requirements upon request from the Planning Coordinator or Transmission Planner. While the NERC
Functional Model is not clear on the function that performs the interconnection study, it likely will be
either the Transmission Planner or the Planning Coordinator. Interconnection studies are typically
long-term planning studies. Thus, it is the Transmission Planner or Planning Coordinator that will
receive the interconnection request and determine on whose equipment will be impacted. R3 is
problematic and contradicts the purpose of R2. R3 requires the Generation Owner that owns
Transmission to have Facility connection requirements at all times. It appears the drafting team
intended for R3 to simply define what must be included in the facility connection requirements. To do
this, we suggest the drafting team remove the Generation Owner that owns Transmission from the
requirement and copy the part 3.1 and its sub-parts to R2. The following language should be struck
from R2: “to ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility connection
requirements”. These requirements already exist elsewhere and inclusion here creates the potential
for double jeopardy. R4 should be struck. There is no need for the Generator Owner that owns
transmission to maintain its facility connection requirements. They should only be required to review
and update them when they get a request. Tariff processes will already require them to make the
facility connection requirements available to interconnection requesters.
Yes
Yes
Yes
Yes
No
No
American Wind Energy Association
Formal Comments on NERC Project 2010-07
Generator Requirements at the Transmission Interface
July 17, 2011
The American Wind Energy Association (AWEA) appreciates the opportunity to
submit these formal comments on the NERC Project 2010-07. AWEA supports the
general direction indicated by both the Generator Requirements at the Transmission
Interface Ad Hoc Group (GOTO Ad Hoc Group), and the Project 2010-07 Standards
Development Team (SDT). We agree with the sentiments from both groups that a
Generator Owner (GO) or Generator Operator (GOP) that also owns or operates a
generator interconnection facility (GIF), should not be required to register as a
Transmission Owner (TO) and/or Transmission Operator (TOP) strictly because they
own or operate the GIF. We also agree that requiring these GOs or GOPs to comply with
all the TO/TOP standards would have little effect on or benefits to reliability of the Bulk
Electric System.
AWEA supports the aim of these groups to address any reliability gap that may exist
with regard to GIFs by considering such facilities as part of the generating facility, and
therefore also subject to the GO/GOP standards. AWEA also supports the approach of
identifying a limited number of TO/TOP standards, such as FAC-001 and FAC-003,
which should also apply to GIFs. We would be concerned, however, if additional
requirements were added beyond these two, without serious consideration by the SDT
and additional industry experts. The recent FERC order on the required registration as
TOs and TOPs of two generator interconnection facilities may raise some question about
the direction that the GO/TO and the SDT have taken so far on this topic. AWEA urges
NERC and the SDT to use caution in considering any additional standards to apply to
GIFs as the current approach of the GO/TO and SDT efforts have been generally
supported. Consideration of any addition standards with respect to GIFs should be done
on a standard-by-standard basis, reviewing the applicability of each standard as well as
the impact on the reliability of the Bulk Electric System.
Contacts:
Natalie McIntire
Consultant to the AWEA
natalie.mcintire@gmail.com
651-964-2599
Tom Vinson
Michael Goggin
Gene Grace
1501 M Street, NW, Suite 1000
Washington, DC 20005
Phone: (202) 383-2500
Fax: (202) 383-2505
Cogeneration Association
of California Comments
Comments on Approach of Project 2010-07
Generator Requirements at the Transmission Interface
The resolution of this issue regarding generator interconnection facilities should compel a certain result
in determining how to classify and register generator tie-lines. Under the current standards, NERC is
compelled to register owners with generator tie-lines as transmission owners. FERC has affirmed this.
The changes to the standards should be such that NERC and FERC are compelled to consider the tie-lines
as part of the generator facilities. The current proposal from this task force does not achieve that result.
While the proposal does make very appropriate changes to certain reliability standards, it does not
change the basic definition of the Bulk Electric System or change NERC’s Statement of Compliance
Registry Criteria, to determine how tie-lines are classified. Even though the relevant reliability standards
would be changed so that they are also applicable to generator facilities, NERC and the regional entities
will continue to apply the same definition and criteria and can continue to classify the tie-lines as
Transmission.
The solution is to change the BES definition and NERC Statement as well as changing the applicability of
the relevant reliability standards. The background resource document from this group suggests that a
change in the BES definition was part of the overall solution, but the Project 2010-17 team did not
address this in its proposed definition. The concept paper from the 2010-17 group does include
“generator interconnection line leads,” but the formal definition paper does not.
This project group should include in its formal proposal a change to the definition of BES, including
generator interconnection facilities within the definition of generation.
Consideration of Comments on Generator
Requirements at the Transmission Interface – Project 2010-07
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments on the first formal posting for Project 2010-07—Generator Requirements at the
Transmission Interface. These standards were posted for a 30-day public comment period from June
17, 2011 through July 17, 2011. The stakeholders were asked to provide feedback on the standards
through a special Electronic Comment Form. There were 43 sets of comments, including comments
from approximately 143 different people from approximately 100 companies representing 9 of the 10
Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
The SDT thanks all stakeholders who provided comments. Your feedback helped the drafting team
further modify its proposed standard changes, and the team believes that the changes are clearer and
more technically sound because of it.
The SDT made a few substantive changes to both FAC-001 and both versions of FAC-003. With respect
to FAC-001, many commenters suggested changes to both R2 and R3 to add clarity. The “activation”
language in R2 now reads “…within 45 days of having an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System…” R3 has been modified so that it is clearer that only
Generator Owners applicable in accordance with R2 are required to comply, and the word “protection”
in R3.1.5 has been made lowercase. Per stakeholder comments, the SDT also removed the Generator
Owner from R4, because they agree that that inclusion was redundant to language in R2. Because
Generator Owners have been removed from the requirement (and thus the requirement is no longer
within the SDT’s scope), the SDT reverted back to the original requirement language in the approved
version of the standard.
Some commenters were still concerned with the 45 day “activation” point, and indicated that more
time could be needed for compliance. The SDT reminded these commenters that the 45 day timeframe
is 45 days from the time the entity has a study Agreement, not 45 days to execute the Agreement
altogether. Any commenters who were concerned that their Facilities could never receive an
interconnection request were reminded that if that’s the case, this standard would never apply to
them. And those commenters who insisted that Generator Owners could never receive a request for
interconnection were reminded that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC
¶ 61,064 at P. 13), Generator Owners have received or have been directed to execute interconnection
requests for their Facilities. Thus, the SDT thinks it is important to clarify the responsibilities related to
such a request in NERC’s Reliability Standards.
With respect to FAC-003, many commenters focused on the half-mile qualifier in both versions of the
standard. Some commenters found the half-mile length too short, others found it too long, and still
others found the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its latest
proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the
fenced area of the generating station switchyard…” The SDT believes that the one mile length is a
reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator
Owner or an auditor. Finally, the team maintains that it is appropriate to include this qualifier for
Generator Owners because there is a very low risk from vegetation within the line of sight, and thus
the formal steps in this standard are not necessary to ensure reliability of these lines.
The majority of commenters did not suggest the addition of any standards or requirements to the
team’s scope of work, and a few commenters cautioned strongly against any additions. Some
commenters suggested that the team consider including those standards and requirements listed in
the June 2011 Cedar Creek and Milford FERC orders. The drafting team has considered the inclusion of
the requirements listed in the Cedar Creek and Milford orders in the past, and we have been revisiting
them throughout our process. We continue to conclude, with stakeholder support, that no additional
substantive standard or requirement changes are necessary to achieve the goal of this project. With
this posting, the drafting team has revisited those standards yet again and developed a comprehensive
document and spreadsheet tracing our rationale (at every stage of the process) for not including
additional standards or requirements. The team has elected to propose a slight clarifying change in
PRC-004-2, but no changes to the applicability of that or any other standard.
While the drafting team will not be adding standards at this time because they do not believe such
additions are technically justified or justified by stakeholder comments, the SDT will be seeking some
additional informal feedback from industry groups to ensure that their technical justifications are
sound and supported by others outside of the drafting team. The current draft documents showing the
team’s rationale and technical justification for including/excluding standards for revision under this
project have been posted for information on the project page with this posting. If you have any specific
feedback on these documents, you are welcome to email mallory.huggins@nerc.net.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf .
Project 2010-07 Consideration of Comments
2
Index to Questions, Comments, and Responses
1.
Do you support the proposed redline changes to FAC-001-1? .................................. 11
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1?.................................................................... 28
3.
Taking into consideration that only one of the versions of FAC-003 will actually be
implemented, a decision that will be made as the Project 2010-07 drafting team learns more
about the status of Project 2007-07—Vegetation Management, do you support the proposed
redline changes to FAC-003-X and FAC-003-3? ..................................................... 33
4.
The drafting team has added Generator Owners to the Applicability sections of FAC-003-X and
FAC-003-3 with the qualifier that the included lines “extend greater than one half mile beyond
the fenced area of the switchyard, generating station or generating substation up to the point
of interconnection with the Transmission system.” The team received many comments about
the need to define a distance rather than other measures for exclusion, and decided on the
one half mile as a reasonable distance. Do you agree with this half-mile qualifier? ..... 43
5.
Do you support the two year compliance timeframe for Generator Owners as included and
explained in the Implementation Plans for FAC-003-X and FAC-003-3?..................... 53
6.
In its background resource document, the drafting team lists the standards that it has not
modified, and offers rationale for its decisions. Are there any reliability standards or
requirements that you believe should apply to Generator Owners or Generator Operators that
own and are responsible for the operation of an overhead Facility, that are not already
applicable or have been proposed to be applicable (FAC-001 and FAC-003) by the Project
2010-07 drafting team? If so, please list them and offer an explanation as to why they should
be applicable to that entity. ................................................................................ 57
7.
Do you have any other questions or concerns with the proposed standards or with the
background resource document that have not been addressed? If yes, please explain.63
Project 2010-07 Consideration of Comments
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Notheast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Gregory Campoli
New York Independent System Operator
NPCC 2
3.
Kurtis Chong
Independent Electricity System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
7.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
8.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9.
Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
NPCC 10
10. Kathleen Goodman ISO - New England
NPCC 2
11. Chantel Haswell
FPL Group, Inc.
NPCC 5
12. David Kiguel
Hydro One Networks Inc.
NPCC 1
13. Michael R. Lombardi Northeast Utilities
NPCC 1
14. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. Saurabh Saksena
National Grid
NPCC 1
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
2.
Gerald Beckerle
Group
SERC OC Standards Review Group
X
2
3
4
5
6
7
8
9
X
Additional Member Additional Organization Region Segment Selection
1.
Scott Brame
NCEMC
SERC
1, 3, 5, 9
2.
Dan Roethemeyer
Dynegy
SERC
4, 5, 6
3.
Jeff Harrison
AECI
SERC
1, 3, 5
4.
Scott McGough
OPC
SERC
5
5.
Alisha Ankar
Prairie Power
SERC
3, 5
6.
Robert Thomasson Big Rivers
SERC
1, 3, 5, 9
7.
Bob Dalrymple
TVA
SERC
1, 3, 5, 9
8.
Dale Donmoyer
Calpine
SERC
5
9.
Richard Dearman
TVA
SERC
1, 3, 5, 9
10. Andy Burch
EEI
SERC
1, 5
11. Eugene Warnecke
Ameren
SERC
1, 3
12. Gene Delk
SCE&G
SERC
1, 3, 5
13. Larry Rodriquez
Entegra
SERC
5
14. Randy Hubbert
Southern
SERC
1, 3, 5
15. Jim Viikinsalo
Southern
SERC
1, 3, 5
16. Marc Butts
Southern
SERC
1, 3, 5
17. Ken Parker
Entegra
SERC
5
18. Bill Autrey
Alabama Power
SERC
1, 3, 5
19. Melvin Roland
Southern
SERC
1, 3, 5
20. Mike McCollum
OPC
SERC
5
21. Mike Hirst
Cogentrix
SERC
5, 6
Project 2010-07 Consideration of Comments
5
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
22. William Berry
OMU
SERC
1, 3, 5
23. Brent Davis
Entergy
SERC
1, 3
24. Brad Young
LGE/KU
SERC
1, 3, 5
25. Wes Davis
SERC
SERC
10
3.
Group
Additional Member
Midwest Reliability Organization's NERC
Standards Review Forum (NSRF)
Carol Gerou
Additional Organization
X
3
X
4
X
5
6
X
X
X
X
7
8
9
Region Segment Selection
1.
Mahmood Safi
Omaha Public Power Dist
MRO
1, 3, 5, 6
2.
Chuck Lawrence
American Transmission Company
MRO
1
3.
Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4.
Jodi Jenson
Western Area Power Administration
MRO
1, 6
5.
Ken Goldsmith
Alliant Energy
MRO
4
6.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
7.
Dave Rudolph
Basin Electric Power Copperative
MRO
1, 3, 5, 6
8.
Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9.
Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
10. Joseph DePoorter
Madison Gas and Electric Company
MRO
3, 4, 5, 6
11. Scott Nichols
Rochester Public Utilities
MRO
4
12. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
13. Richard Burt
Minnkota Power Copperative
MRO
1, 3, 5, 6
14. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
15. Scott Bos
Muscatine Power and Water
MRO
3, 4, 5, 6
16. Lee Kittleson
Otter Tail Power Company
MRO
5, 1, 3, 6
17. Marie Knox
Midwest ISO
MRO
2
4.
Connie Lowe
Group
X
2
Electric Market Policy
X
X
Additional Member Additional Organization Region Segment Selection
1. Mike Crowley
SERC
1
2. Louis Slade
RFC
5, 6
3. Michael Gildea
NPCC 5, 6
4. Mike Garton
MRO
Project 2010-07 Consideration of Comments
5, 6
6
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5.
Group
Additional Member
Charles W. Long
SERC Planning Standards Subcommittee
Additional Organization
Ameren Services Co.
SERC
1
2. James Manning
NC Electric Membership Corp. SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Pat Huntley
SERC Reliability Corp.
SERC
10
5. Bob Jones
Southern Company Services
SERC
1
Group
3
4
5
6
7
8
9
X
Jesus Sammy Alcaraz
Imperial Irrigation District (IID)
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Tino Zaragoza
IID
WECC 1
2. Jesus Sammy Alcaraz IID
WECC 3
3. Diana Torres
IID
WECC 4
4. Marcela Caballero
IID
WECC 5
5. Cathy Bretz
IID
WECC 6
7.
Group
Brent Ingebrigtson
No additional members listed.
LG&E and KU Energy
X
X
X
X
8.
Public Service Enterprise Group
X
X
X
X
Group
John Seelke
Additional Member Additional Organization Region Segment Selection
1. Ken Brown
PSE&G
RFC
1, 3
2. Clint Bogan
PSEG Fossil
RFC
5
3. Peter Dolan
PSEG ER&T
RFC
6
4. Scott Slickers
PSEG Fossil
NPCC
5
5. Eric Schmidt
PSEG ER&T
NPCC
6
6. Mikhail Falkovich
PSEG Fossil
ERCOT 5
9.
Group
SPP Reliability Standards Development
Team
Jonathan Hayes
X
Additional Member Additional Organization Region Segment Selection
1. Valerie Pinamonti
AEP
SPP
1, 3, 5
2. Newton Alan Ward
AEP
SPP
1, 3, 5
Project 2010-07 Consideration of Comments
10
X
Region Segment Selection
1. John Sullivan
6.
2
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Mahmood Safi
OPPD
SPP
1, 3, 5
4. John Allen
SPRM
SPP
1, 4
5. Mitch Williams
Western Farmers
SPP
1, 3, 5
6. Robert Cox
Lee County Electric
7. Don Reinert
Westar
SPP
1, 3, 5, 6
8. Robert Rhodes
SPP
SPP
2
10.
Group
Additional Organization
PPL Supply Group
Leland McMillan
PPL Montana, LLC
2.
Don Lock
Lower Mount Bethel Energy, LLC RFC
5
3.
PPL Brunner Island, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Martins Creek, LLC
RFC
5
6.
PPL Montour, LLC
RFC
5
Mark Heimbach
PPL EnergyPlus, LLC
MRO
6
PPL EnergyPlus, LLC
NPCC
6
9.
PPL EnergyPlus, LLC
RFC
6
10.
PPL EnergyPlus, LLC
SERC
6
11.
PPL EnergyPlus, LLC
SPP
6
12. John Cummings
PPL EnergyPlus, LLC
WECC 6
11.
Jason Marshall
Additional Member
5
6
7
8
9
Additional Organization
X
ACES Power Members
X
Region Segment Selection
1. Darin Adams
East Kentucky Power Cooperative SERC
1, 3, 5
2. Susan Sosbe
Wabash Valley Power Association RFC
3
3. Mohan Sachdeva
Buckeye Power
3, 5
RFC
12.
Individual
Chris Higgins
Bonneville Power Administration
13.
Individual
Jack Cashin
EPSA
14.
Individual
Sandra Shaffer
PacifiCorp
X
15.
Individual
Janet Smith, Regulatory
Arizona Public Service Company
X
Project 2010-07 Consideration of Comments
X
WECC 5
8.
Group
4
Region Segment Selection
1.
7.
3
NA
Annette Bannon
Additional Member
2
X
X
X
X
X
X
X
X
X
X
X
X
8
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
Affairs Supervisor
16.
Individual
Bo Jones
Westar Energy
17.
Individual
Antonio Grayson
Southern Company
X
18.
Individual
Mike Laney
Luminant Power
X
19.
Individual
Thad Ness
American Electric Power
X
X
X
20.
Individual
Edward Cambridge
APS
X
X
X
21.
Individual
Gretchen Schott
BP Wind Energy North America Inc.
Individual
23. Individual
Katy Mirr
Brian Evans-Mongeon
Sempra Generation
Utility Services, Inc.
24.
Individual
Samuel Reed
Tri-State Generation and Transmission, Inc.
X
25.
Individual
Alice Ireland
Xcel Energy
X
26.
27.
Individual
Individual
Jody Nelson
Bill Rees
Georgia Transmission Corporation
BGE
X
X
28.
Individual
John Bee
Exelom
X
29.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
30.
Individual
Dale Fredrickson
Wisconsin Electric
Individual
32. Individual
Keith Morisette
Joe Petaski
Tacoma Power
Manitoba Hydro
33.
Individual
Greg Rowland
Duke Energy
34.
Individual
Amir Hammad
Constellation Power Generation
Individual
36. Individual
Kirit Shah
Rex Roehl
Ameren
Indeck Energy Services
X
X
X
X
37.
Individual
Chad Bowman
CHPD
X
X
X
38.
Individual
Andrew Z Pusztai
American Transmission Company
X
39.
Individual
Michael Falvo
Independent Electricity System Operator
22.
31.
35.
Project 2010-07 Consideration of Comments
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
40.
Individual
Doug Hohlbaugh
FirstEnergy Corp
X
Individual
42. Individual
Sandy O'Connor
X
Natalie McIntire
TransAlta Centralia Generation LLC
American Wind Energy Association
43.
Donald Brookhyser
Cogeneration Association of California
41.
Individual
Project 2010-07 Consideration of Comments
2
3
X
4
X
5
X
6
7
8
9
X
X
10
10
1. Do you support the proposed redline changes to FAC-001-1?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-001, and and the team has made additional changes,
based on commenter feedback, where they believe those changes add clarity.
Commenters suggested changes to both R2 and R3 to add clarity. The “activation” language in R2 now reads
“…within 45 days of having an executed Agreement to evaluate the reliability impact of interconnecting a third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to the Transmission System…” R3 has
been modified so that it is clearer that only Generator Owners applicable in accordance with R2 are required to
comply, and the word “protection” in R3.1.5 has been made lowercase. Per stakeholder comments, the SDT also
removed the maintenance requirements for the Generator Owner from R2, and the Generator Owner from R4
altogether. Because Generator Owners have been removed from the requirement (and thus the requirement is no
longer within the SDT’s scope), the SDT reverted back to the original requirement language in the approved version
of the standard.
Some commenters were still concerned with the 45 day “activation” point, and indicated that more time could be
needed for compliance. The SDT reminded these commenters that the 45 day timeframe is 45 days from the time
the entity has a study Agreement, not 45 days to execute the Agreement altogether. Any commenters who were
concerned that their Facilities could never receive an interconnection request were reminded that if they are correct,
this standard would not apply to them. Those commenters who insisted that Generator Owners could never receive a
request for interconnection were reminded that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC
¶ 61,064 at P. 13), Generator Owners have received or have been directed to execute interconnection requests for
their Facilities. Thus, the SDT believes it is important to clarify the responsibilities related to such a request in NERC’s
Reliability Standards.
Some commenters brought up tariff-related issues. While the SDT has made changes attempting to clarify what was
perceived by some commenters to be ambiguous qualifying language in R2, and while the commenters are correct
that a valid interconnection would likely need to go through the generator interconnection process under its
applicable tariff, it would be inappropriate for any market- or tariff-related language to be included in a NERC
Reliability Standard. The goal of the drafting team was simply to clarify a Generator Owner’s obligations, under
NERC’s Reliability Standards, for handling an interconnection request and the related interconnection requirements.
Several commenters also suggested changes to VRFs and VSLs. Because the SDT did not make any substantive
changes to R1 or R4, the team only made changes to the VSLs or VRFs if we were correcting a typo; anything
substantive would be outside the scope of this SDT. In the case of R2 and R3, changes were made per commenter
suggestions.
Finally, the formatting error in the Applicability section has been corrected.
Project 2010-07 Consideration of Comments
11
For a more detailed explanation of the team’s rationale, please see the accompanying FAC-001-1 technical
justification.
Organization
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes or No
Question 1 Comment
No
In general, the NSRF supports the changes to FAC-001-1. However the 45 days to execute an
agreement would be a significant burden on a Generator Operator that does not have an
existing process in place. The NSRF believes an aggressive but realistic time frame is 120 days.
This would allow sufficient time to develop the procedure and obtain the necessary technical
and legal reviews.
Please clarify why "Protection" is capitalized in section 3.1.5. "Protection System" is defined by
NERC but "System Protection" is not.
Recommend the "half mile" statement be included within the Applicability section of this
Standard as it stated in FAC-003-X.
Response: Thank you for your comment. The team proposed 45 days from the time the entity has a study Agreement, not 45 days to
execute the Agreement altogether. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of
the team’s rationale for using that time frame. No change made.
“Protection” in 3.1.5 has been made lowercase.
With respect to the “half mile” comment, an entity could receive an interconnection request for its interconnection Facility at any point along
that Facility. An exemption or exclusion based on the length of the Facility is not justified because doing so would create a reliability gap. No
change made.
Public Service Enterprise
Group
No
The language in R2 needs to be clarified with regards to the term “its existing generation
Facility.” The interconnection leads are considered part of the “existing generation Facility,”
but so are the generator, generator step-up transformer and other equipment associated with
the generator. The project Background Resource Document (p.2) makes it clear that the
interconnection to an existing generator facility is contemplated to be to the “existing
interconnecting Facility that is owned by a generator” - i.e., the generator’s interconnection
leads. We propose that the term “its existing generation Facility” be replaced with “the
Generator Owner’s existing interconnecting transmission Facility.”
Response: Thank you for your comment. We agree that some additional specification could be useful, and we have used the suggested
Project 2010-07 Consideration of Comments
12
Organization
Yes or No
Question 1 Comment
clarifying language.
SPP Reliability Standards
Development Team
No
We are concerned that some of the language is ambiguous. We would like to be clear that
placing new requirements on Generator Owners that are already in place and have been in
place under FERC policy is inaccurate. We want to make sure that regardless of what the
generator tie line is classified as, that a valid interconnection would go through the Generator
Interconnection process under its applicable tariff.
Format error in 2.4.1 should read 4.2.1 in applicability.
We would like to see more definition in applicability section 4.2. How does the Generator
Owner get involved in this process?
The VRF for R4 is listed as a medium and appears to us as an administrative requirement. We
would recommend that the VRF be changed to low.
The moderate and high VSL for R1 seems to be duplicative. We would recommend taking a
second look and would recommend that the high should be that “if you failed to do two of the
following”.
We would recommend that the VSL on R4 read: “The responsible entity failed to make the
requirements available within 30 business days after a request.”
Response: Thank you for your comment. We have attempted to clarify what was perceived by some commenters to be ambiguous qualifying
language. You are correct that a valid interconnection would likely need to go through the generator interconnection process under its
applicable tariff, but it would be inappropriate for any market- or tariff-related language to be included in a NERC Reliability Standard. The
goal of the drafting team was simply to clarify a Generator Owner’s obligations, under NERC’s Reliability Standards, for handling an
interconnection request and the related interconnection requirements.
The format error in the applicability section has been corrected.
A Generator Owner can get involved in the process by receiving a request for interconnection on their Facility and executing an Agreement to
evaluate the reliability impact of that request. The team has attempted to clarify to qualifying language in the applicability section with its
latest proposed changes. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s
rationale.
With respect to the VRF for R4, we agree that “low” might be more appropriate, but that change is outside the scope of this drafting team.
Your suggestion will be submitted in a Suggestion Form and added to NERC’s Issues Database to be addressed in a future project.
Project 2010-07 Consideration of Comments
13
Organization
Yes or No
Question 1 Comment
With respect to the moderate and high VSLs for R1, we agree that they are duplicative and believe this was a typo. Change made.
With respect to the proposed language change in the VSL for R4, while we agree that the VSL should be written in the negative rather than
the positive that change would be outside the scope of this drafting team. Your suggestion will be submitted in a Suggestion Form and added
to NERC’s Issues Database to be addressed in a future project.
PPL Supply Group
No
A Generator Owner subject to the proposed standard (i.e., with an executed Agreement to
evaluate the reliability impact of interconnecting another Facility to its existing generation
Facility) should only be responsible for evaluating the impact of such interconnection on its
facilities. Generation Owners should have no responsibility for evaluating impacts on
interconnected or adjacent Transmsision Owner systems. GOs do not have staff trained or tools
available to perform the studies necessary to evaluate reliability impacts of such
interconnections on Transmission Owner systems which can exend geographically far beyond
the POI. The SDT should clarify that Transmission Owners are solely responsible for evaluating
and addressing any impacts on their systems.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. The drafting team does not believe the
standard as written requires the Generator Owner to be responsible for any interconnection Facility past the point of interconnection with the
Transmission Owner’s Facility. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the
team’s rationale. No change made.
ACES Power Members
No
We support the concept of modifying FAC-001-1 to include Generation Owners that own
transmission lines that interconnect them to the BES for the purpose of eliminating the need to
register Generation Owners as Transmission Owners. However, there are serious issues with
the implementation of the FAC-001-1. The changes conflict with the tariff process of many
established markets as well as the FERC pro forma tariff. Requests to interconnect are
generally governed by tariffs. The request will be submitted to the transmission provider
established by the tariff. The transmission provider will then perform the necessary studies
such as system impact or feasibility studies to determine any necessary upgrades through its
long-term planning function. After the completion of these studies or in parallel with them, the
Transmission Owner (or Generation Owner that owns transmission) will perform the facility
connection study. This may or may not require an additional contract as it may be governed
completely under the tariff or may be covered under a blanket agreement in an organized
Project 2010-07 Consideration of Comments
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Question 1 Comment
market. The language referring to the executed Agreement in the standard should be dropped
as it is confusing and may not cover many situations. Rather, the standard should apply to the
Generation Owner that owns Transmission and is not registered as Transmission Owner.
R2 should be modified such as the Generation Owner that owns Transmission is required to
create facility connection requirements upon request from the Planning Coordinator or
Transmission Planner. While the NERC Functional Model is not clear on the function that
performs the interconnection study, it likely will be either the Transmission Planner or the
Planning Coordinator. Interconnection studies are typically long-term planning studies. Thus, it
is the Transmission Planner or Planning Coordinator that will receive the interconnection
request and determine on whose equipment will be impacted.
R3 is problematic and contradicts the purpose of R2. R3 requires the Generation Owner that
owns Transmission to have Facility connection requirements at all times. It appears the
drafting team intended for R3 to simply define what must be included in the facility connection
requirements. To do this, we suggest the drafting team remove the Generation Owner that
owns Transmission from the requirement and copy the part 3.1 and its sub-parts to R2. The
following language should be struck from R2: “to ensure compliance with NERC Reliability
Standards and applicable Regional Entity, subregional, Power Pool, and individual Transmission
Owner planning criteria and Facility connection requirements”. These requirements already
exist elsewhere and inclusion here creates the potential for double jeopardy. R4 should be
struck. There is no need for the Generator Owner that owns transmission to maintain its facility
connection requirements. They should only be required to review and update them when they
get a request. Tariff processes will already require them to make the facility connection
requirements available to interconnection requesters.
Response: Thank you for your comment. The drafting team believes that the execution of an Agreement to evaluate the reliability impact of
interconnecting a third party Facility is the appropriate “activation” point for this standard for applicable Generator Owners. We have changed
the language in the requirement to accommodate situations where it was not the Generator Owner itself that executed the Agreement. Please
see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s rationale.
R3 has been modified to more clearly apply only to Generator Owners in accordance with R2. Per your suggestion about maintenance, the
drafting team has removed the maintenance obligation for Generator Owners. For more information on our rationale with respect to this,
please see the accompanying FAC-001-1 technical justification document.
Westar Energy
No
We suggest the VRF for R4 be changed from medium to low, as it is administrative in nature.
We recommend the high VSL for R1 read, “The Transmission Owner failed to do two of the
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Question 1 Comment
following.”
Response: Thank you for your comment. We agree that “low” might be more appropriate, but that change is outside the scope of this
drafting team. Similarly, any change to the VSLs for R1 is outside the scope of this drafting team as that requirement does not include any
reference to Generator Owners; we only made changes if the previous text appeared to have a typo. Your suggestions will be submitted in a
Suggestion Form and added to NERC’s Issues Database to be addressed in a future project.
Southern Company
No
A. Southern does not think that the revision to FAC-001-1 is necessary. A Generator Owner
(GO) cannot assess reliability impacts to the Bulk Electric System (BES) and determine
acceptability without support and involvement of the applicable owner and operator of the
Transmission System. A generator tie-line does not equate to a Transmission System. A GO
must already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties facilities to its own interconnection Facilities.
Stated another way, the GO does not need Facility Connection requirements to govern how
multiple units are tied to a collector bus so why are they needed for a third party to connect to
an existing tie-line? In either case it is the interconnected TO that has connection requirements
that must be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its interconnected
Transmission Provider. A GO should not need to develop “connection requirements” unless it is
in the business of owning and operating facilities independently of its interconnected
Transmission Provider.
We do not believe a reliability gap exists in FAC-001-1 because the requestor for
interconnecting another Facility to an existing generation Facility must coordinate with the
applicable TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable
facility connection and performance requirements. If and when there is an agreement in place
for a third party to connect to a generator tie-line then the tie-line would become part of the
integrated system and its purpose and the owner’s function would likely warrant registration as
a TO/TOP and FAC-001 would then apply. The following excerpt from the 2010-07 Background
Resource Document acknowledges that this may be necessary: “The drafting team also
acknowledges that, if another party interconnects to a Facility owned by a Generator Owner,
there may be the need to address MOD or TPL standards. However, the drafting team believes
that this, too, is best handled through specific evaluation, perhaps accompanied by changes to
the compliance registry. Entities that face this kind of scenario may also meet criteria applicable
to other registrations such as Transmission Service Provider or Transmission Planner.”
Project 2010-07 Consideration of Comments
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Question 1 Comment
B. If the Project 2010-07 Drafting Team decides to continue revising FAC-001-1, there are
jurisdictional, interconnection policy and open access transmission tariff issues that will need to
be considered.
(1) Because of (a) jurisdiction under Section 215, (b) FERC’s interconnection policy, and (c)
the requirements of the pro forma open access transmission tariff (OATT), a GO should not be
required to comply with FAC-001-1 until that GO’s generating Facility reaches commercial
operation.
(a) Jurisdiction under FPA Section 215. First, it is not clear that NERC or FERC has
jurisdiction under FPA Section 215 to require generation facilities that have not actually
reached commercial operation to be subject to reliability standards. Section 215(a)(2) of
the FPA defines the “Electric Reliability Organization” as “the organization certified by the
Commission ... the purpose of which is to establish and enforce reliability standards for
the bulk-power system, subject to Commission review.” Further, (a)(3) provides that “The
term ‘reliability standard’ means a requirement, approved by the Commission under this
section, to provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide for
reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design of
planned additions or modifications. It is logical to interpret the phrase “design of new
facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted as
requiring that a generating facility that has not yet reached commercial operation should
be subject to reliability standards (including audit and penalties). Therefore, the GO with
the existing generation facilities should not be required to incorporate the proposed
generation facility into its Facility connection requirements before the proposed generation
facility is subject to NERC or FERC jurisdiction.
(b) FERC’s interconnection policy. In addition, the revised FAC-001 would appear to
place restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC was
very concerned about the ability of interconnection customers to interconnect their
generating facilities and gave them a fair amount of flexibility. However, this revised
Project 2010-07 Consideration of Comments
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Question 1 Comment
FAC-001 would appear to restrict some of this flexibility.
(i) Order No. 2003 gives the interconnection customer the ability to terminate a
proposed interconnection on ninety days notice. Therefore, the interconnection
customer is not required to build the facility. However, this revised FAC-001
appears to assume that the interconnection customer does not have this flexibility.
What if the interconnection customer (the GO building a new generator on its site
or the third party building a new generation facility) decides to terminate the Large
Generator Interconnection Agreement (LGIA) or not proceed with the generation
facility? In such event, the GO may be required to revert to its previous Facility
connection requirements in order to accommodate the original configuration.
(ii) The LGIA permits modifications to the proposed interconnection. How would
this affect the Facility connection requirements? How long would the GO have to
revise its Facility connection requirements? In the event that there is a single
modification, or perhaps multiple modifications, how does the GO stay in
compliance with this standard?
(iii) FAC-001-1, R4 provides that each GO with Facility connection requirements
and each TO shall maintain Facility connection requirements and make
documentation of these requirements available to users of the Transmission
System upon request. However, Large Generator Interconnection Procedures
(LGIP), Section 3.4 requires the posting of certain interconnection information but
the identity of the interconnection customer is not to be disclosed (unless it is an
Affiliate). Requirement R4 would appear to potentially require disclosure of
information and (more importantly) of the interconnection customer's identity in
contravention of the requirements in Order No. 2003 and the LGIP.
(c) OATT requirements. The definition of “applicable Generator Owner” (Section 4.2.1)
and Requirement R2 provide that the GO will have an executed Agreement to evaluate
the impact of interconnecting a new facility to the GO’s existing generation facility. This
statement is ambiguous. This statement could be understood to mean that the GO of the
existing generation Facility will enter into an Agreement with the GO proposing to
interconnect and the existing GO will evaluate the impact of the proposed interconnection.
However, requests to interconnect new generation are processed under an OATT. In that
case, it would be the Transmission Provider (not the existing GO) that would evaluate the
impact of interconnecting the new facility. Thus, the language in FAC-001-1 would need
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Question 1 Comment
to be revised to clarify that the owner of the new facility will need to interconnect under
the OATT of an appropriate Transmission Provider (i.e., the Transmission Provider to
which the existing GO is interconnected, not with the existing GO). Therefore, the owner
of the new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be developing
a merchant transmission line. In that case, the existing GO would need to evaluate
whether it needs have its own OATT and OASIS. In that case, the new generator owner
would be interconnecting to the existing GO. However, the existing GO’s line would not
be a generator tie-line. This issue is not clear from the draft standard.
(2) The following are suggested changes to FAC-001-1.
(a) We recommend the Purpose statement be revised to state, “To avoid adverse impacts
on BES reliability...”
(b) The numbering for “Applicable Generator Owner” should be 4.2.1 instead of 2.4.1.
(c) It is not clear who may request to interconnect to the Generator Owners’ facility. The
Background Resource document states that “[b]ecause Generator Owners may be
requested to allow interconnection to their Facilities” - this would imply that a third party
may request interconnection to the Generator Owner’s Facilities. However, draft FAC001-1 discusses “interconnecting another Facility to its existing generation Facility.” This
issue needs to be clarified. Is it simply when a Generator Owner proposes to add a new
facility to its existing facility or does it also include a third party request to interconnect to
the Generator Owner facilities?
(d) R4 should be revised to delete the requirement to maintain the Facility connection
requirements because this is redundant to language in R1 (and R2, which we believe is
not needed). In addition, R4 should be revised to state, “...on requests within five (5)
business days” since the time requirement is essential for measurement of noncompliance as indicated by the VSLs.
(e) The Severe VSL for R3 should be revised to delete the second portion which states,
“The responsible entity does not have Facility connection requirements.” This noncompliance would be covered by the first portion of the two-part OR requirement (...four
or more...). It is also covered by the Severe VSL of R1.
(3) Effect of the proposed revisions to FAC-001-1 on FAC-002-1.
Project 2010-07 Consideration of Comments
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(a) As drafted, there are scenarios under which a new GO may attempt to interconnect to
an existing GO even though, as explained above, the interconnection should actually be
done to the appropriate Transmission Provider. If the appropriate Transmission Provider
is not included in the evaluation of the interconnection various types of harm may occur.
In such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002.
(b) FAC-001 and FAC-002 should be revised to be clear that the existing GO and any new
GOs must coordinate any interconnection with the appropriate Transmission Provider, TP
and PA.
Response: Thank you for your comment. The drafting team has considered the jurisdictional, interconnection policy and open access
transmission issues that you raise. But in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. You are correct that a jurisdictional,
interconnection policy, and open access transmission tariff issues maybe have an impact, but it would be inappropriate for any market- or
tariff-related language to be included in a NERC Reliability Standard. The goal of the drafting team was simply to clarify a Generator Owner’s
obligations, under NERC’s Reliability Standards, for handling an interconnection request and the related interconnection requirements. Please
see the SDT’s accompanying FAC-001-1 technical justification for a more detailed explanation of the team’s rationale.
With respect to your suggested changes in section 2:
a. Any change to the purpose statement would be outside the scope of this team. Please submit a Suggestion Form to NERC if you continue
to feel that this change is necessary.
b. That formatting change has been made.
c. The drafting team has worked to clarify who may request to interconnect to the Generator Owner’s Facility.
d. The maintenance requirements in R2 and R4 are no longer applicable to Generator Owners. For more information on our rationale on this
issue, please see the accompanying FAC-001-1 technical justification document.
e. The drafting team agrees that the second portion of the Severe VSL for R3 is redundant. While other changes to VSLs and VRFs have been
outside the scope of the team, because the SDT has made changes to R3, we feel comfortable making this change.
For a more detailed justification of our changes to FAC-001 with respect to your comments in the third section, please see the FAC-001
justification document that is posted with these standard changes.
American Electric Power
No
There are substantial reliability issues, as well as additional regulatory, tariff, coordination, and
generator and interconnection facility issues, which need to be dealt with before AEP could
agree to such requirements. It is not clear that a generator can receive a request for
Project 2010-07 Consideration of Comments
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Yes or No
Question 1 Comment
interconnection. We recommend adding qualifier text which states the standard only applies
*if* an entity plans to allow such a requested interconnection. This would allow an entity to
document that they do not plan to allow such interconnections.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. No change made.
APS
No
Do not agree with adding GO to FAC-001-1
Response: Thank you for your comment. The vast majority of stakeholder commenters and the drafting team continue to support the
addition of the Generator Owner to the applicability of FAC-001-1. No change made.
Exelon
No
Exelon does not agree that this standard should be broadly applied to a GO. GOs who do not
own a switchyard and whose point of interconnection is a disconnect switch associated with the
generator leads prior to the switchyard should be excluded from this standard. If a group of
GOs share a generator tie line, then the associated Interconnect Agreement that each of the GO
has with the applicable TO and/or TOP should address how these shared connections will effect
the system. GOs may not have the resources or expertise to conduct the required interconnect
studies to meet this standard
Response: Thank you for your comment. The standard does not automatically apply to all Generator Owners; rather, it applies only to those
Generator Owners with an executed Agreement to evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the Transmission System. The drafting team believes that it has built the appropriate
amount of time into the standard to allow an applicable Generator Owner to evaluate the impact of an Interconnect Agreement and obtain or
contract for the necessary resources and expertise. Please see the SDT’s accompanying FAC-001-1 technical justification for a more detailed
explanation of the team’s rationale. No change made.
Manitoba Hydro
No
The Applicable Entities now include a Generator Owner that meets the following condition:
‘Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting another Facility to its existing generation Facility.’ A Generator Owner should
not have such power. In many instances Generator Owners do not have the models or
expertise to perform interconnection studies to determine if there is an impact on the
Transmission Network. All interconnection requests should be implemented by the
Transmission Owner (TO) regardless if the interconnection point is within a Generation Owner
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Question 1 Comment
facility or End-User facility. The TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If a mechanism is created to
allow interconnection to a BES line owned by Generator Owner, then it is essential for this
Generator Owner providing this interconnection service to be a TO to ensure all reliability
standards, including the protection standards, are met so the reliability of the BES is
maintained. The drafting team should demonstrate where this situation is occurring.If the
redline changes are implemented, could Generator Owner #1 permit Generator Owner #2 to
interconnect one of their generators within Generator Owner #1’s Facility? Would Generator
Owner #2 then need to have an executed Agreement to permit further generator
interconnection? From a Transmission Owner viewpoint, it is tough enough to coordinate
generator connection queues among adjacent TOs. Having to coordinate with Generator
Owners as well would greatly increase the complexity of coordination.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator
Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is
important to clarify the responsibilities related to such a request in NERC’s Reliability Standards. No change made.
American Transmission
Company
No
R1 wording in this draft only requires having published Facility connection requirements, but
speaks nothing of specific required content of this published document. (R1) VSLs specifically
reference R1. If VSLs continue to include assessment of how many R3 (R2 in present standard)
requirements are met, a TO potentially has a redundant obligation under two separate
requirements. R1 and R3 do not read in a manner consistent with (R1) VSLs. Since R2 only
applies to Generator Owners, the (R2) VSL should use “Generator Owner” in place of
“responsible entity.”
Response: Thank you for your comment. The drafting team has removed the second portion of the Severe VSL for R3 to eliminate potential
redundancy with the VSLs for R1 and R2. The VSL for R2 now refers to “Generator Owner” rather than “responsible entity.”
Xcel Energy
Yes
We believe it would be helpful to put explanatory wording in that if an entity is already
registered as a Transmission Owner and Generator Owner, the Generator Owner portion of that
entity would not have to have a separate set of interconnection requirements.
Response: Thank you for your comment. The Facility in question in the standard would either be owned by the Generator Owner or the
Transmission Owner. The owner must meet the requirement. The SDT does not determine how an entity complies, though we could expect
that if an entity is already an Transmission Owner, it could easily simply apply its already existing set of interconnection requirements to any
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Question 1 Comment
new Facilities that are applicable under this standard.
Ingleside Cogeneration LP
Yes
However, there may need to be a variance for ERCOT because the Power Generating
Companies in ERCOT are not allowed to own transmission assets.
Response: Thank you for your comment. If companies in ERCOT are not allowed to own transmission assets, the drafting team assumes that
they would also never be in a position to have an Agreement to execute the reliability impact of an interconnection request. No change made.
Georgia Transmission
Corporation
Yes
We commend the drafting team for their efforts to address gaps in Facility Connection
Requirements. We believe that the requirements under R3 should be limited to Generator
owned equipment to avoid duplication of efforts. A Generator Owner receiving an
interconnection request is required to submit an interconnection request to the Transmission
Owner which in turn would study the impact of such a request on the Transmission System.
Therefore there is no gap as far as the Integrated Transmission System that the third party is
interconnecting to through the Generator Owner. However, Generator Owners are responsible
for verifying that their equipment is capable of accommodating the interconnection request.
Response: Thank you for your comment. The SDT does not believe that R3 is duplicative; there is no reason to assume that the
Transmission Owner or the applicable Generator Owner would be addressing anything but the equipment that it owns. No change made.
BGE
Yes
This change closes the gap in areas not already covered under FAC-003-1 in a continuous
improvement effort to ensure vegetation-related transmission reliability for applicable lines.
Response: Thank you for your comment.
FirstEnergy Corp
Yes
FirstEnergy (FE) appreciates the drafting team's careful consideration of the comments made
by FE during the most recent informal comment peroid. The changes made to FAC-001
alleviate FE's prior concern related to a Generator Owner needing to maintain and publish a
Facility Connection requirements document regarding facilities which are not yet subject to
Open Access provisions. FE supports the team's changes to FAC-001-1 and the concept that a
connection requirement document would be required upon the initial or 1st time a Generator
Owner executes an Agreement to perform the reliability assessment required in FAC-002-1.
Response: Thank you for your comment.
Project 2010-07 Consideration of Comments
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Organization
Sempra Generation
Yes or No
Yes
Question 1 Comment
Sempra Generation supports the proposal for the compliance obligations under R2 associated
with an interconnection request not to be triggered until an interconnection study agreement
has been executed.
Response: Thank you for your comment.
Arizona Public Service
Company
Yes
These comments supersede the previous comments submitted by Arizona Public Service
Company on July 7, 2011.
Response: Thank you for your comment.
SERC OC Standards Review
Group
Yes
Consider a better definition of what constitutes an “applicable” generator owner or point to the
document that explains the definition.
Response: Thank you for your comment. The drafting team attempted to clarify the description of an “applicable” Generator Owner in the
latest standards changes.
Imperial Irrigation District
(IID)
Yes
PacifiCorp
Yes
Ameren
Yes
Luminant Power
Yes
Constellation Power
Generation
Yes
SERC Planning Standards
Subcommittee
Yes
Duke Energy
Yes
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Tri-State Generation and
Transmission, Inc.
Yes
Electric Market Policy
Yes
Bonneville Power
Administration
Yes
Indeck Energy Services
Yes
CHPD
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Tacoma Power
Yes
Notheast Power Coordinating
Council
Yes
TransAlta Centralia
Generation LLC
Yes
EPSA
Question 1 Comment
Background: The Electric Power Supply Association (EPSA) endorsed the initial
recommendations of the Ad Hoc Group for Generator Requirements at the Transmission
Interface, offered informal comments on the March 2011 White Paper Proposal for Project
2010-07 and now appreciates this opportunity to provide comments on the questions posted
June 17, 2011. Since NERC’s creation of the “GOTO Team” in February of 2009, EPSA has
supported the efforts of Ad-Hoc Group and now the Project 2010-07 Standards Drafting Team
(SDT). While EPSA members’ compliance registration includes several functional entity types,
the bulk of competitive suppliers’ registrations are as Generator Owners (GOs) and Generator
Project 2010-07 Consideration of Comments
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Question 1 Comment
Operators (GOPs).
EPSA applauds the SDT’s decision to recommend the use the “intent of obligation” as the
reason for application of FAC-001 rather than the receipt of request for interconnection and
thereby supports the revisions to FAC-001-1. The proposed modification to FAC-001 (a new R2)
would require a GO to develop “Facility connection requirements” within “45 days of executing
an Agreement to evaluate the reliability impact of interconnecting another Facility to its existing
generation Facility...” The use of the agreement execution is a more reasonable triggering
mechanism for FAC-001 application and compliance. The SDT’s recommendation intentionally
excluded specific reference to the form of agreement to avoid commingling commercial and
reliability aspects in reliability standards.
However, the existing language may still may mix commercial and reliability issues. The
accompanying project Background Resource Document (p.2) makes it clear that the
interconnection to an existing generator facility is contemplated to be the “existing
interconnecting Facility that is owned by a generator” - that is, the generator’s lead. The
generator’s leads are considered part of the “existing generator Facility,” however, the
generator, step-up transformer and other equipment that is within the generator switchyard
can also be considered part of the Facility. FERC requires all transmission facilities to be
available for “open access.” A generator lead would become open access if another customer
interconnected to it. Therefore FAC-001-1 could be made clearer by modifying the language
regarding the 45-day trigger as follows: within “45 days of executing an Agreement to evaluate
the reliability impact of interconnecting another Facility to its the Generator Owner’s existing
generation interconnecting transmission Facilities...” This modification would make it clear that
the requirement does not apply to an entity that wants to, for example, connect a new
generator within the fenced-in site of the existing generator, but instead only applies to request
to interconnect to the generator lead.
Response: Thank you for your comment. The drafting team has attempted to make this clarification regarding the “activation” of the
applicability of this standard with respect to Generator Owners.
Utility Services, Inc.
LG&E and KU Energy
Project 2010-07 Consideration of Comments
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Organization
Yes or No
Question 1 Comment
Wisconsin Electric
Project 2010-07 Consideration of Comments
27
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan
for FAC-001-1?
Summary Consideration: Most commenters supported the one year compliance timeframe for Generator Owners
as proposed in the Implementation Plan for FAC-001-1. A few suggested a longer timeframe, but the drafting team
believes it has built in the appropriate amount of time by giving a year in the implementation plan and then waiting
to “activate” the standard until a Generator Owner has an executed Agreement to evaluate the reliability impact of
the interconnection request.
Organization
Manitoba Hydro
Yes or
No
No
Question 2 Comment
See question #1 comments. We do not support changing the applicability of FAC001-1 to include Generator Owners ‘with an executed Agreement’ or Generator
Owners that own BES transmission.
Response: Thank you for your comment. Please see our response to your Question 1 comments above.
Ingleside Cogeneration LP
No
As drafted, the document still refers to generation interconnection lines as
transmission lines in critical places. We understand that the SDT has taken
significant steps to minimize this in both FAC-001 and FAC-003 and has had
discussions with NERC about not registering GOs as TOs; however, this lack of
distinction between high voltage generation interconnection lines and actual
transmission lines still presents a difficult situation for Generations Owners and a
source of contention with Reliability Entities. This could be resolved somewhat by
using the non-defined term “generation interconnection lines” in place of
“transmission lines” in, for example, section 4.3.1. Since the term “transmission line”
is also undefined, this would seem to be a reasonable approach.
Response: Thank you for your comment. We have provided a disclaimer about the use of the term “transmission lines” in FAC003, and have avoided use of the term elsewhere.
APS
No
Leave the GO out of the standard.
Response: Thank you for your comment. In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their Facilities, and the drafting
Project 2010-07 Consideration of Comments
28
Organization
Yes or
No
Question 2 Comment
team thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability Standards by including
applicable Generator Owners in FAC-001-1.
SERC OC Standards Review
Group
No
We feel that an 18 month implementation plan would be more conducive for
generators to meet these new requirements
Response: Thank you for your comment. The drafting team believes it has built in an adequate amount of time by giving a year in
the implementation plan and then waiting to “activate” the standard until a Generator Owner has an executed Agreement to
evaluate the reliability impact of the interconnection request.
PPL Supply Group
No
It may take longer since very few (if any) GOs are prepared to perform this type of
work.
Response: Thank you for your comment. The drafting team believes it has built in the appropriate amount of time by giving a
year in the implementation plan and then waiting to “activate” the standard until a Generator Owner has an executed Agreement
to evaluate the reliability impact of the interconnection request.
BGE
Yes
This requirement is consistent with the initial time frame when FAC-003-1 was first
implemented.
Response: Thank you for your comment.
Southern Company
Yes
However, we do not believe it is necessary to require a GO to have Facility connection
requirements as we discuss in our response to Question 1.
Response: Thank you for your comment. Please see our response to your Question 1 comments above.
FirstEnergy Corp
Yes
The one year lead time is sufficient lead-time to notice the GOs of new expectations
required under FAC-001-1.
Response: Thank you for your comment.
Notheast Power Coordinating
Yes
Project 2010-07 Consideration of Comments
29
Organization
Yes or
No
Question 2 Comment
Council
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
SPP Reliability Standards
Development Team
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
EPSA
Yes
PacifiCorp
Yes
Arizona Public Service
Company
Yes
Project 2010-07 Consideration of Comments
30
Organization
Yes or
No
Westar Energy
Yes
Luminant Power
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Tacoma Power
Yes
Duke Energy
Yes
Constellation Power
Generation
Yes
Ameren
Yes
Indeck Energy Services
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
Project 2010-07 Consideration of Comments
Question 2 Comment
31
Organization
TransAlta Centralia
Generation LLC
Yes or
No
Question 2 Comment
Yes
Georgia Transmission
Corporation
Wisconsin Electric
Utility Services, Inc.
Exelom
LG&E and KU Energy
American Transmission
Company
Project 2010-07 Consideration of Comments
32
3. Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will
be made as the Project 2010-07 drafting team learns more about the status of Project 2007-07—Vegetation
Management, do you support the proposed redline changes to FAC-003-X and FAC-003-3?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-003-X and FAC-003-3, and the drafting team made
additional changes, based on commenter feedback, where the team believes those changes add clarity.
Many commenters focused on the half-mile qualifier in FAC-003-X and FAC-003-3. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the
switchyard, generating station, or generating substation to be confusing. The drafting team attempted to address all
of these concerns with its latest proposed standard changes. The qualifier now reads: “…that extends greater than
one mile beyond the fenced area of the generating station switchyard…” The drafting team believes that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of the
generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an
auditor. Finally, the team maintains that it is appropriate to include this qualifier for Generator Owners because there
is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are not
necessary to ensure reliability of these lines.
One commenter caught typos in the Effective Dates sections of the standards, and those typos have been corrected.
Single commenters brought up minority issues, but the SDT found no justification for these issues. We address those
minority issues in our responses to the specific comments below.
Organization
American Transmission
Company
Yes or
No
No
Question 3 Comment
ATC does not support the changes for FAC-003-X, however, ATC does support
FAC-003-3.
FAC-003-X Concerns. The VRF and VSL tables do not correlate to the original
FAC-003-1 levels of non-compliance section D.2. ATC believes that section D.2
should be rewritten to align with the already approved FAC-003-1.
FAC-003-X Corrections- Applicability Section 4.3.1, sentence 3 - Transmission
should not be capitalized.
Project 2010-07 Consideration of Comments
33
Organization
Yes or
No
Question 3 Comment
FAC-003-3 - No Concerns
Response: Thank you for your comment. The VSLs and VRFs in FAC-003-X were taken from already approved NERC
projects to update all early versions of standards with VSLs and VRFs instead of levels of non-compliance. Any additional
changes to those VSLs and VRFs would be beyond the scope of this drafting team. No change made.
Applicability Section 4.3.1 no longer includes a capitalized version of Transmission (just a reference to the “Transmission
Owner’s Facility”).
Public Service Enterprise
Group
No
FAC-003-X and FAC-003-3 both have similar “one half mile” language, the
starting point for the one half mile is vague. In FAC-003-X, the language in
4.3.1 reads “Generator Owner that owns an overhead Facility that extends
greater than one half mile beyond the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection
with the Transmission system and ...” While we support the one half mile
language, there are three possible staring points for the measurement of the
one half mile: beyond the fenced area of (i) the switchyard, (ii) the generating
station, or (iii) the generation substation. While a GO’s fencing policy may
differ between generation stations, the requirement to implement vegetation
management should be clear. For clarity, while we believe that the language
should retain flexibility with regards to “fencing” by the Generator Owner, it
should be clear that the Generation Owner determines the starting point.
Second, a Generator Owner’s overhead Facility that is within the fence should
explicitly not be applicable to the standard. Finally, we believe the language
that refers to the “interconnection with the Transmission system” should be
changed to “interconnection with a Transmission Owner’s Facility. The reason
is that the term “Transmission” which is defined in the NERC Glossary could be
construed to include all of a Generator Owner’s interconnection leads. (The
definition is excerpted from the Glossary in our response to question 7)
Therefore, we suggest that the language in 4.3.1 be modified as follows to
make all of these points clear: A Generator Owner that owns an overhead
Facility that extends greater than one half mile beyond the fenced area of
either the generator switchyard, generating station or generating substation
(as specified by the Generation Owner) up to the point of interconnection with
Project 2010-07 Consideration of Comments
34
Organization
Yes or
No
Question 3 Comment
a Transmission Owner’s Facility and is operated 200 kV and above and any
lower voltage lines designated by the RE as critical to the reliability of the
electric system within the region is applicable to this standard.”
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team agrees that “interconnection with a Transmission Owner’s Facility” adds clarity. That change has been
made.
SPP Reliability Standards
Development Team
No
In both FAC-003-3 and FAC-003-X it lists “greater than one half mile cutoff”.
We would recommend that the distance cutoff be removed. We feel that
overhead Facilities shouldn’t be treated any differently than any other. Also we
would like to see these two sections in both standard proposals reflect similar
language for 4.3.1.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Project 2010-07 Consideration of Comments
35
Organization
PPL Supply Group
Yes or
No
No
Question 3 Comment
Version 3 (based on V2): Third Effective date appears to contain a
typographical error.
Version X (based on V1): Same as Version 3 comments.
Please consider streamlining the section Background (Version 3).
Response: Thank you for your comment. The typographical errors were corrected in both versions of the standard.
Streamlining the Background section in Version 3 is not within the scope of this drafting team. No change made.
Westar Energy
No
The language in the applicability section 4.3.1 in both FAC-003-3 and FAC-003X states “extends greater than one half mile beyond...” We propose that the
SDT consider removing the distance exclusion to be consistent with language
for Transmission Owner Facilities and treat all overhead facilities the same.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Southern Company
No
(1) We question whether R1 of FAC-003-3 would ever apply to a GO who owns
transmission interconnection equipment. Can the SDT provide an example or
two in the Guideline and Technical Basis section of the standard?
(2) We recommend rearranging the language in R5 of FAC-003-3 to state, “The
applicable Transmission Owner or applicable Generator Owner shall take
corrective action to ensure continued vegetation management to prevent
encroachments when...” This places the “shall” at the beginning of the
Project 2010-07 Consideration of Comments
36
Organization
Yes or
No
Question 3 Comment
requirement which is clearer and consistent with the structure of the other
requirements.
(3) We question why there are no VSLs assigned to R4. Should there be?
What are the consequences if a Regional Entity does not comply?
(4) There does not appear to be any coordination with the Vegetation
Management Standard Drafting Team (VMSDT) concerning proposed
modifications to the standard. The VMSDT should be consulted.
Response: Thank you for your comment.
(1) The SDT is not currently aware of specific examples where R1 would apply, but we do not see any reason to remove that
reference, as it could apply in the future. If we removed it now, we’d create a reliability gap, but if we leave it in, no
Generator Owner has to take action unless it has an IROL or WECC transfer path.
(2) This change is beyond the scope of our drafting team. It is an issue that should have been addressed under Project
2007-07. We will submit the issue in a Suggestion Form to be added to NERC’s Issues Database.
(3) Because the Regional Entity is not a Functional Entity, it cannot be assigned penalties under NERC’s Reliability Standards.
(4) The Project 2007-07 Vegetation Management drafting team’s latest draft standard has already passed ballot, so
coordination with that team was no longer a possibility.
APS
No
Leave the GO out of both Standards proposed.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making
both FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the
generator interconnection Facility are covered under NERC Reliability Standards. No change made.
Indeck Energy Services
No
4.3.1.3 is a regional variation. The ROP doesn't permit members of one region
to vote on regional requirements for another region. A separate regional
standard will be required.
Response: Thank you for your comment. It is our understanding that any stakeholder can vote on regional requirements as
long as they’re in the body of the standard. This does not require a separate regional standard.
Project 2010-07 Consideration of Comments
37
Organization
Ingleside Cogeneration LP
Yes or
No
Question 3 Comment
No
Ingleside Cogeneration LP believes there should be a relaxation in the
vegetation management requirements for those interconnections which only
serve as a radial link to the BES. Although we fully understand the importance
of keeping vegetation away from high voltage lines, the one year period is
much too frequent in our generator locations. The added documentation and
other expenses simply do not justify the non-existent gain in reliability when
vegetation in a locale (e.g.; desert) never reaches five feet above the ground.
Consider limiting this exception to units below a certain MVA rating that are not
critical to the BES - perhaps coupled with evidence that vegetative intrusions
are highly unlikely.
Response: Thank you for your comment. We have attempted to set up a reasonable qualifier/balance with the new one mile
designation and “stake in the ground” at the fenced line of the switchyard. Because of a perceived reliability gap at the
interconnection between Generator Owner Facilities and Transmission Owner Facilities, we are doing our best to apply the
same Transmission Owner vegetation management requirements to the Generator Owner. This issue you raise (with respect
to the vegetation in certain locales) could possibly be applied to other entities besides the Generator Owner if it was
technically justified, so the drafting team encourages you to submit a SAR suggesting this.
Notheast Power Coordinating
Council
No
See comments in the following questions.
EPSA
Yes
EPSA generally supports the SDT’s proposed redline changes to FAC-003-X and
FAC-003-3 and SDT’s diligence in monitoring Project 2007-07. There is one
distinction however that EPSA would like to bring to the SDT’s attention that
could increase clarity. FAC-003-X and FAC-003-3 both have similar “one half
mile” language, but the starting point for the one half mile can occur one of
three ways.
In FAC-003-X, the language in 4.3.1 reads “Generator Owner that owns an
overhead Facility that extends greater than one half mile beyond the fenced
area of the switchyard, generating station or generating substation up to the
point of interconnection with the Transmission system and ...” Therefore,
there are three possible staring points for the measurement of the one half
mile: beyond the fenced area of (i) the switchyard, (ii) the generating station,
Project 2010-07 Consideration of Comments
38
Organization
Yes or
No
Question 3 Comment
or (iii) the generation substation. While it would appear implicit that GO’s
would determine which of the three was used to make the determination that
the GO determines the starting point.
Another point for consideration is that a Generator Owner’s overhead Facility
that is within the fence should explicitly not be applicable to the standard.
EPSA believes the language that refers to the “interconnection with the
Transmission system” should be changed to “interconnection with a
Transmission Owner’s Facility. The reason is that the term “Transmission”
which is defined in the NERC Glossary could be construed to include all of a
Generator Owner’s interconnection leads. Therefore, we suggest that the
language in 4.3.1 be modified as follows to make all of these points clear:A
Generator Owner that owns an overhead Facility that extends greater than one
half mile beyond the fenced area of either the generator switchyard, generating
station or generating substation (as specified by the Generation Owner) up to
the point of interconnection with the Transmission Owner’s Facility and is
operated 200 kV and above and any lower voltage lines designated by the RE
as critical to the reliability of the electric system within the region is applicable
to this standard.”
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team agrees that “interconnection with a Transmission Owner’s Facility” adds clarity. That change has been
made.
Project 2010-07 Consideration of Comments
39
Organization
BGE
Yes or
No
Yes
Question 3 Comment
As noted in Question-1 above.
Response: Thank you for your comment. See our response to Question 1.
SERC OC Standards Review
Group
Yes
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Arizona Public Service
Company
Yes
Luminant Power
Yes
Project 2010-07 Consideration of Comments
40
Organization
Yes or
No
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Georgia Transmission
Corporation
Yes
Exelom
Yes
Duke Energy
Yes
Constellation Power
Generation
Yes
Ameren
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Yes
Project 2010-07 Consideration of Comments
Question 3 Comment
41
Organization
Yes or
No
Question 3 Comment
Generation LLC
LG&E and KU Energy
Manitoba Hydro
Tacoma Power
Wisconsin Electric
Utility Services, Inc.
Project 2010-07 Consideration of Comments
42
4. The drafting team has added Generator Owners to the Applicability sections of FAC-003-X and FAC-003-3 with the
qualifier that the included lines “extend greater than one half mile beyond the fenced area of the switchyard,
generating station or generating substation up to the point of interconnection with the Transmission system.” The
team received many comments about the need to define a distance rather than other measures for exclusion, and
decided on the one half mile as a reasonable distance. Do you agree with this half-mile qualifier?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The majority of
comments indicated support for the SDT’s changes to FAC-003-X and FAC-003-3, and the drafting team has made
additional changes, based on commenter feedback, where they think those changes add clarity.
The drafting team received many comments about the half-mile qualifier in FAC-003-X and FAC-003-3. Some
commenters found the half-mile length too short, others found it too long, and still others found the choice among
the starting points of the switchyard, generating station, or generating substation to be confusing. The drafting team
attempted to address all of these concerns with its latest proposed standard changes. The qualifier now reads:
“…that extends greater than one mile beyond the fenced area of the generating station switchyard…” The SDT
believes that the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point
(at the fenced area of the generation station switchyard) eliminates confusion and any discretion on the part of a
Generator Owner or an auditor. Finally, the team maintains that it is appropriate to include this qualifier for
Generator Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps
in this standard are not necessary to ensure reliability of these lines.
One commenter suggesting including the equivalent kilometer length in the qualifying language in the standard, and
we have made that change.
Organization
Northeast Power
Coordinating Council
Yes or
No
No
Question 4 Comment
The qualifier should be similar to that specified in Part 4.2.4 of FAC-003-3:
“This standard applies to overhead transmission lines identified above (4.2.1
through 4.2.3) located outside the fenced area of the switchyard, station or
substation and any portion of the span of the transmission line that is crossing
the substation fence. “ Vegetation needing attention can exist within a half
mile of a switchyard. Vegetation does not discriminate between Generation
and Transmission Owners.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC-003-
Project 2010-07 Consideration of Comments
43
Organization
Yes or
No
Question 4 Comment
X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others found the
choice among the starting points of the switchyard, generating station, or generating substation to be confusing. The drafting
team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now reads: “…that
extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of the generation
station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor. Finally, we
maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from vegetation
within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these lines.
SPP Reliability Standards
Development Team
No
See comment above. We feel like there is no need for using a distance
exclusion.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
PPL Supply Group
No
Version 3 (based on V2):Comments: Although the “one half mile” is much
clearer than “two spans”, what is the rationale for choosing ½ mile as
opposed to another length such as 1 or 2 miles? Version X (based on V1):
Same as Version 3 comments
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
Project 2010-07 Consideration of Comments
44
Organization
Yes or
No
Question 4 Comment
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Bonneville Power
Administration
No
BPA believes that there needs to be a clear demarcation where Transmission
Owner and Generator Owner responsibilities begin and end.
Response: Thank you for your comment. The drafting team is operating under the assumption the Generator Owner’s
responsibilities to its interconnection Facility up to the point of interconnection with the Transmission Owner’s Facility, and
we have attempted to make that clear in our draft standards. We are considering changes to the definitions of Generator
Owner and Generator Operator, or creation of new terms to provide additional clarity in the next steps of our project plan,
pending Standards Committee approval.
Arizona Public Service
Company
No
The generator should be responsible no matter the length from fence area to
the point of interconnection.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Southern Company
No
Project 2010-07 Consideration of Comments
We agree with a one-half mile line as being “within the Generator Owner’s line
of sight and could be visually monitored for vegetation conditions on a routine
basis.” However, we suggest that some generation interconnection Facilities
greater than ½ mile in length could also fall within the GO’s line of sight or be
constructed such that they should be considered for exemption. Thus, the
Task Force should consider including exclusions for longer generator tie lines if
45
Organization
Yes or
No
Question 4 Comment
the GO can provide sufficient justification. Examples of justifications could
include (1) a clear line of sight, (2) pavement, gravel, or other non-vegetation
covered path, or (3) routine monitoring is performed from a roadway parallel to
the line, etc. Do not obviate any other transmission requirements such as the
following (which are incorporate into the draft standard):i. Operated at 200kV
or higher; orii. Operated below 200kV and included in IROL; or iii. Operated
below 200kV and inclusion in a Major WECC Transfer Path
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The issue you raise with respect to justification for further exclusions could possibly be applied to other entities besides the
Generator Owner (assuming it was technically justified), so the drafting team encourages you to submit a SAR suggesting
this.
APS
No
Leave GOs out of the standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making
both FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the
generator interconnection Facility are covered under NERC Reliability Standards. No change made.
Ingleside Cogeneration LP
No
The SDT needs to clarify that the one-half mile distance is measured from the
property line of the Generation Owner, i.e., an interconnection line that is in a
ROW.In addition, the half mile qualifier makes sense only for those
interconnections into critical generation facilities. See our response under
Question #3.
Project 2010-07 Consideration of Comments
46
Organization
Yes or
No
Question 4 Comment
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Wisconsin Electric
No
In addition to the "greater than one-half mile" criteria, we maintain there
should also be an exclusion for lines up to one mile in length which are entirely
on the Generator Owner's property.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Ameren
No
(1)We do not agree there should be a ½ mile exemption. On what legitimate
basis could we say the first ½ mile is not important? (2) There may be
different usage of the term "point of interconnection" in the industry. We
suggest the SDT to consider proposing a formal definition of this term.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
Project 2010-07 Consideration of Comments
47
Organization
Yes or
No
Question 4 Comment
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
The drafting team is considering proposing a formal definition of the term “point of interconnection,” or other definitional
changes to make the use of that term clearer.
Westar Energy
No
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Although the NSRF agrees with the 1/2 mile criteria (see question 1); we
believe the drafting team will have to develop additional justification for this
criteria given FERC's recent orders, RC11-1 and RC11-2 (see question 6 for full
FERC Order details). In these orders FERC "implies" that if the GO/GOP is
responsible for a breaker operated at 100kV or higher the entity should be
required to register as a TOP/TO. Therefore it appears FERC would not be
inclined to provide any leeway based on distance from the substation. The SDT
should note that the FERC Order points to this Project to "address matters
involving reliability obligations at the interface of the transmission grid", which
is foot note 58.
Response: Thank you for your comment.
SERC Planning Standards
Subcommittee
Yes
However, we are concerned that there may be a reliability gap for locations
where there is not a half-mile line-of-sight from the generation switchyard.
Response: Thank you for your comment. The SDT believes these cases are limited enough that an exclusion within the
standard is not necessary. If you believe it is, we encourage you submit to a Suggestion Form.
EPSA
Yes
Project 2010-07 Consideration of Comments
EPSA appreciates the SDT proposing to use the approach that provides a
48
Organization
Yes or
No
Question 4 Comment
specific distance for determining which GO Facility lead lines that FAC-003
should apply to. EPSA agrees that the half-mile qualifier provides a discrete
parameter that will limit ambiguity in the Standard.
Response: Thank you for your comment.
LG&E and KU Energy
Yes
Although the “one half mile” is much clearer than “two spans”, what is the
rationale for choosing ½ mile as opposed to another length such as 1 or 2
miles?
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FAC003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Independent Electricity
System Operator
Yes
We generally agree with the proposed distance. However, we suggest that in
Applicability Section 4.3.1 of the two draft standards, an equivalent kilometer
value be inserted after the “one half mile”.
Response: Thank you for your comment. We have added the equivalent kilometer value.
SERC OC Standards Review
Group
Yes
While we agree, we believe that a better explanation of “the fenced area of the
switchyard, generating station or generating substation up to the point of
interconnection with the Transmission system” should be included. One
suggestion is to distinguish between a plant perimeter fence and an internal
switchyard fence.
Response: Thank you for your comment. The drafting team received many comments about the half-mile qualifier in FACProject 2010-07 Consideration of Comments
49
Organization
Yes or
No
Question 4 Comment
003-X and FAC-003-3. Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating substation to be confusing.
The drafting team attempted to address all of these concerns with its latest proposed standard changes. The qualifier now
reads: “…that extends greater than one mile beyond the fenced area of the generating station switchyard…” We believe that
the one mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.
Finally, we maintain that it is appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
BGE
Yes
1/2 mile is a distance that can generally be viewed from one location, e.g. the
switchyard, and can be construed to present minimal risk since switchyards
have a reasonably frequent personnel presence that could be expected to
notice vegetation issues in the <1/2 mile area.
Response: Thank you for your comment.
Electric Market Policy
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
ACES Power Members
Yes
PacifiCorp
Yes
Luminant Power
Yes
American Electric Power
Yes
Project 2010-07 Consideration of Comments
50
Organization
Yes or
No
Xcel Energy
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
BP Wind Energy North
America Inc.
Yes
Georgia Transmission
Corporation
Yes
Exelom
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Generation LLC
Yes
Duke Energy
Yes
Indeck Energy Services
Yes
Constellation Power
Generation
Yes
CHPD
Yes
Question 4 Comment
Utility Services, Inc.
Manitoba Hydro
Project 2010-07 Consideration of Comments
51
Organization
Yes or
No
Question 4 Comment
Tacoma Power
American Transmission
Company
Project 2010-07 Consideration of Comments
52
5. Do you support the two year compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X and FAC-003-3?
Summary Consideration: The SDT thanks all individuals and groups who provided feedback. The vast majority of
commenters supported the two-year compliance timeframe for Generator Owners as included and explained in the
Implementation Plan. One commenter suggested that one year would be sufficient because most lines will be short,
but the SDT pointed out that the distances of the lines can vary, and Generator Owners that have not been
practicing any sort of vegetation management will need to hire new staff and develop a full vegetation management
plan, which could take longer than the year given to Transmission Owners for implementation of FAC-003-1. No
changes were made to the two-year compliance timeframe, although the team has modified FAC-003-3’s
implementation plan to account for a few different scenarios that could occur with respect to the filing of FAC-003-2
and FAC-003-3
Organization
Ingleside Cogeneration LP
Yes or
No
Question 5 Comment
No
The two year compliance time frame makes sense only for those GOs who own
interconnections into critical generation facilities. See our response under Question #3.
Response: Thank you for your comment. It is unclear whether you find the two year timeframe too long or too short, or if you
believe that the standard should only apply to Generator Owners who own interconnections into critical generation facilities. No
change made.
Please see our response to your comments under Question 3 above.
APS
No
Leave GOs out of the standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
Arizona Public Service
Company
No
The generator should be able to be in compliance within one year since the distance of
line miles is small.
Response: Thank you for your comment. The distances of the lines can vary, and Generator Owners that have not been practicing
any sort of vegetation management will need to hire new staff and develop a full vegetation management plan, which could take
Project 2010-07 Consideration of Comments
53
Organization
Yes or
No
Question 5 Comment
longer than the year given to Transmission Owners for implementation of FAC-003-1. No change made.
Notheast Power
Coordinating Council
Yes
SERC OC Standards Review
Group
Yes
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
Electric Market Policy
Yes
SERC Planning Standards
Subcommittee
Yes
Imperial Irrigation District
(IID)
Yes
Public Service Enterprise
Group
Yes
SPP Reliability Standards
Development Team
Yes
PPL Supply Group
Yes
ACES Power Members
Yes
Bonneville Power
Administration
Yes
Project 2010-07 Consideration of Comments
54
Organization
Yes or
No
EPSA
Yes
PacifiCorp
Yes
Westar Energy
Yes
Southern Company
Yes
Luminant Power
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Sempra Generation
Yes
Tri-State Generation and
Transmission, Inc.
Yes
Xcel Energy
Yes
Georgia Transmission
Corporation
Yes
BGE
Yes
Exelom
Yes
Wisconsin Electric
Yes
Duke Energy
Yes
Project 2010-07 Consideration of Comments
Question 5 Comment
No comment.
55
Organization
Yes or
No
Constellation Power
Generation
Yes
Ameren
Yes
Indeck Energy Services
Yes
CHPD
Yes
Independent Electricity
System Operator
Yes
FirstEnergy Corp
Yes
TransAlta Centralia
Generation LLC
Yes
Question 5 Comment
Utility Services, Inc.
LG&E and KU Energy
Tacoma Power
Manitoba Hydro
American Transmission
Company
Project 2010-07 Consideration of Comments
56
6. In its background resource document, the drafting team lists the standards that it has not modified, and offers
rationale for its decisions. Are there any reliability standards or requirements that you believe should apply to
Generator Owners or Generator Operators that own and are responsible for the operation of an overhead Facility,
that are not already applicable or have been proposed to be applicable (FAC-001 and FAC-003) by the Project 201007 drafting team? If so, please list them and offer an explanation as to why they should be applicable to that entity.
Summary Consideration: The SDT thanks all stakeholders for their feedback. The majority of commenters did not
suggest the addition of any standards or requirements to the team’s scope of work, and a few commenters cautioned
strongly against any additions. Some commenters suggested that the team consider including those standards and
requirements listed in the June 2011 Cedar Creek and Milford FERC orders. The drafting team has considered the
inclusion of the requirements listed in the Cedar Creek and Milford orders in the past, and has been revisiting them
throughout our process. They have continued to conclude, with stakeholder support, that no additional substantive
standard or requirement changes are necessary to achieve the goal of this project. With this posting, the drafting
team has revisited those standards yet again and developed a comprehensive document and spreadsheet tracing
their rationale (at every stage of the process) for not including additional standards or requirements. The team has
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other
standard.
While the SDT will not be adding standards at this time because they do not believe such additions are technically
justified or justified by stakeholder comments, the team will be seeking some additional informal feedback from
industry groups to ensure that their technical justifications are sound and supported by others outside of the drafting
team. The team has posted their current draft rationale and technical justification documents on the project webpage
with this posting. If you have any specific feedback on these documents, you are welcome to email
mallory.huggins@nerc.net.
Organization
Manitoba Hydro
Yes or
No
Question 6 Comment
No
The direction of the background resource document gives special treatment to the
Generator Owner in that it allows the Generator Owner TO status for a couple of
standards (FAC-001 and FAC-003), but exempts the Generator Owner from many of the
standards applicable to a TO. The NERC Functional Model defines the various functional
entities. If a Generator Owner wants to be a TO, all the Requirements applicable to a TO
should apply. There is no need to change specific Reliability Standards to allow the
Project 2010-07 Consideration of Comments
57
Organization
Yes or
No
Question 6 Comment
Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The purpose of the drafting team is “To propose a set of changes to existing
requirements and definitions, as well as additional requirements and definitions, that collectively adds significant clarity to
Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the interconnected
grid. This global strategy is proposed to expedite the closing of the reliability gap.” The SDT is applying select Transmission Owner
standards to Generator Owners, not attempting to give them TO status.
Sempra Generation
No
No, Sempra Generation believes the Project 2010-07 Team has effectively indentified the
Standards and Requirements that should apply to Generator Owners or Generator
Operators that own, and are responsible for, the operation of an overhead Facility, that
are not already applicable or have been proposed to be applicable.
Response: Thank you for your comment.
APS
No
Leave GOs and GOPs out of the FAC-001 and FAC-003 standards.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
SERC OC Standards
Review Group
No
Electric Market Policy
No
SERC Planning Standards
Subcommittee
No
Imperial Irrigation District
(IID)
No
SPP Reliability Standards
No
Project 2010-07 Consideration of Comments
58
Organization
Yes or
No
Question 6 Comment
Development Team
ACES Power Members
No
EPSA
No
PacifiCorp
No
Arizona Public Service
Company
No
Westar Energy
No
Luminant Power
No
American Electric Power
No
BP Wind Energy North
America Inc.
No
Tri-State Generation and
Transmission, Inc.
No
Xcel Energy
No
Georgia Transmission
Corporation
No
BGE
No
Exelom
No
Project 2010-07 Consideration of Comments
No comment.
59
Organization
Yes or
No
Ingleside Cogeneration LP
No
Wisconsin Electric
No
Duke Energy
No
Constellation Power
Generation
No
Ameren
No
Indeck Energy Services
No
CHPD
No
Independent Electricity
System Operator
No
FirstEnergy Corp
No
TransAlta Centralia
Generation LLC
No
Public Service Enterprise
Group
Yes
Question 6 Comment
FERC’s Cedar Creek and Milford order (issued on June 16, 2011 and that is posted at
http://www.nerc.com/files/Order_Denying_Appeals_RC11-1_RC11-2_20110616.pdf)
listed several standards (in Paragraphs 71 and 87) that should be applicable to Cedar
Creek and Milford, respectively. Because of this order, the drafting team should
examine the listed standards and determine whether they are or are not applicable to
Generator Owners or Generator Operators that own and are responsible for the
operation of an overhead Facility. We emphasize that our recommendation takes no
position on any legal issues regarding the referenced order.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Project 2010-07 Consideration of Comments
60
Organization
Yes or
No
Question 6 Comment
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We have
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. Please
see the accompanying resource documents for more information.
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
Yes
In FERC order "Denying Appeals of Electric Reliability Organization Registration
Determinations" dated June 16, 2011 (RC11-1 and RC11-2) FERC explicitly stated
compliance GAPs existed with the following standards at a minimum: o FAC-011,
Requirements R2, R2.1, R2.2. o PRC-001-1, Requirements R2, R2.2, R4; o PRC-004-1
Requirement R1; o TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4; o PER-0031, Requirements R1, R1.1, R1.2; o FAC-003-1, Requirements R1, R2; o TOP-001,
Requirement R1 and o FAC-014-2, Requirement R2. When a GO/GOP owns
transmission equipment but is not registered as a TO or TOP. The drafting team should
explicitly address each of these the above requirements.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We have
elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. Please
see the accompanying resource documents for more information.
Tacoma Power
Yes
Tacoma Power suggests that three standards be reconsidered for inclusion in this
Project, to include the Generator Owner and/or Operator: EOP-005, more directly
responsible for participation in restoration plans; PER-002, responsible for training; and
VAR-001.
Response: Thank you for your comment. We have considered the inclusion of additional standards and requirements throughout
our process and we continue to conclude, with stakeholder support, that no additional substantive standard or requirement changes
are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those standards yet again and
developed a comprehensive document and spreadsheet tracing our rationale (at every stage of the process) for not including
Project 2010-07 Consideration of Comments
61
Organization
Yes or
No
Question 6 Comment
additional standards or requirements. We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the
applicability of that or any other standard. Please see the accompanying resource documents for more information. The SDT does
not agree that VAR-001 should be applied to a GOP as VAR-002 @R2 already requires the GOP to “maintain the generator voltage
or Reactive Power output (within applicable Facility Ratings) as directed by the Transmission Operator.” We believe this is sufficient
in meeting the purpose of VAR-001.
Southern Company
Yes
Bonneville Power
Administration
Yes
Please see our Comments in response to Question 7.
PPL Supply Group
Notheast Power
Coordinating Council
LG&E and KU Energy
Utility Services, Inc.
American Transmission
Company
Project 2010-07 Consideration of Comments
62
7. Do you have any other questions or concerns with the proposed standards or with the background resource
document that have not been addressed? If yes, please explain.
Summary Consideration: The SDT thanks all stakeholders who offered additional feedback in this section. Some
comments revisited issues that had been addressed in other questions, and other comments introduced new minority
concerns.
A few commenters suggested, again, the inclusion of definitions or additional standards within the scope of this
project, and the SDT appreciates those comments, especially those which included detailed suggestions. While the
team is not proposing any definition changes with this round of updated standard changes, they do plan to consider
some definition changes or possibly new definitions to prevent future unnecessary registration of GOs and GOPs as
TOs and TOPs and ensure that there are no possible reliability gaps. In the next steps of our project, we will consider
putting forward definition-related changes for comment separately, following the procedure approved by the
Standards Committee after its July 2011 meeting.
The SDT has also considered the inclusion of additional standards and requirements throughout our process and
continues continue to conclude, with stakeholder support, that no additional substantive standard or requirement
changes are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those
standards yet again and developed a comprehensive document and spreadsheet tracing our rationale (at every stage
of the process) for not including additional standards or requirements. The team has elected to propose a slight
clarifying change in PRC-004-2, but no changes to the applicability of that or any other standard. They have
attempted to make our technical justifications much more robust and comprehensive than they were in the past, as
suggested by stakeholders. Please see the accompanying resource documents (posted on the project webpage) for
more information.
One commenter expressed concern about whether the SDT’s work would be approved by regulators. The drafting
team is doing everything we can to work with regulating entities to ensure that forced registrations no longer occur.
For most of the comments, the team made no changes and explained why:
One commenter suggested modifying the definition of Right-of-Way in the currently approved FAC-003-1 (our FAC003-X). The team could not make any change because the definition proposed in FAC-003-3 has not been formally
approved and, in general, modifications to the definition of ROW are outside the scope of our team.
One commenter suggested modifications to the format of the requirements in FAC-003-X, which the SDT determined
to be outside its scope.
Project 2010-07 Consideration of Comments
63
One commenter expressed concern about a Transmission Owner or Generator Owner having to comply with FAC-003
for a Facility that it did not own. The drafting team does not know why a Transmission Owner or Generator Owner
would ever be required to provide evidence, documentation, notification, or inspection of vegetation management for
Facilities not owned by that registered entity, except where explicitly agreed upon in a contract. In the absence of
additional information to clarify this commenters concern, the SDT does not believe this needs to be addressed
within the standard.
One commenter focused on FAC-001 and expressed concern about the “activation” point of the standard and the
feasibility of any interconnection. The SDT reminded the commenter that “activation only occurs with an executed
Agreement, and that in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their Facilities.
One commenter wondered why only a select set of TO/TOP requirements were being applied to GOs/GOPs. The SDT
directed this commenter to the goal of the team, which is to apply select Transmission Owner standards to Generator
Owners, not to give them TO status.
Organization
TransAlta Centralia
Generation LLC
Yes or
No
No
Question 7 Comment
TransAlta Centralia Generation LLC (TransAlta) supports the recommendations put
forward by the Project 2010-07 drafting team. The implementation of these
recommendations will provide for much needed certainty for owners and operators of
generation facilities.
Response: Thank you for your comment.
SERC Planning Standards
Subcommittee
No
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers.
Response: Thank you for your comment.
CHPD
No
BP Wind Energy North
No
Project 2010-07 Consideration of Comments
64
Organization
Yes or
No
Question 7 Comment
America Inc.
Ameren
No
Independent Electricity
System Operator
No
Tri-State Generation and
Transmission, Inc.
No
Electric Market Policy
No
Georgia Transmission
Corporation
No
BGE
No
Duke Energy
No
SPP Reliability Standards
Development Team
No
Imperial Irrigation District
(IID)
No
Midwest Reliability
Organization's NERC
Standards Review Forum
(NSRF)
No
Xcel Energy
No
Luminant Power
No
Project 2010-07 Consideration of Comments
No comment.
65
Organization
Yes or
No
Wisconsin Electric
No
ACES Power Members
No
Arizona Public Service
Company
No
Westar Energy
No
Bonneville Power
Administration
No
SERC OC Standards Review
Group
No
Notheast Power
Coordinating Council
Yes
Question 7 Comment
Regarding the Right-of-Way definitions, the definition in FAC-003-3 is the better of the
two. Suggest adding “and maintain” to the first sentence of the definition as follows:
The corridor of land under a transmission line(s) needed to operate and maintain the
line(s). The width of the corridor is established by engineering or construction
standards as documented in either construction documents, pre-2007 vegetation
maintenance records, or by the blowout standard in effect when the line was built. The
ROW width in no case exceeds the applicable Transmission Owner’s or applicable
Generator Owner’s legal rights but may be less based on the aforementioned criteria.
The term Right-of-Way goes beyond Transmission Vegetation Management, and that
should be considered in the definition. How does Right-of-Way affect transmission
facilities that are routed over bodies of water, or over valleys, highways, etc.? Rightof-Way in relation to underground facilities? The format of FAC-003-X should be made
consistent with current NERC guidelines (i.e.--Parts of Requirements should not have
R’s in their numbering, should be 1.1, 1.2 etc.).
Response: Thank you for your comment. It would be outside the scope of this team to modify the definition of Right-of-Way in the
currently approved FAC-003-1 (our FAC-003-X), because the definition proposed in FAC-003-3 has not been formally approved and,
in general, modifications to the definition of ROW are outside the scope of our team. No change made.
Project 2010-07 Consideration of Comments
66
Organization
Yes or
No
Question 7 Comment
With respect to the changes to the format of the requirements in FAC-003-X, while our drafting team is making changes to update
the format of the standard where possible, we do not think it is appropriate to change the listing of the sub-requirements to parts.
In earlier versions of standards, the sub-requirements were written as requirements (for instance, they have their own VSLs), and
we do not believe it is appropriate within our scope to make that format and labeling change.
Public Service Enterprise
Group
Yes
While we generally agree with the drafting team’s modifications to these standards, the
team’s approach may not directly resolve the fundamental registration issue regarding
a Generation Owner that only owns non-integrated interconnection transmission
facilities. The non-integrated interconnection transmission facilities owned by a GO are
part of the Bulk Electric System (BES) because they are part of BES generation
facilities. The ownership of these non-integrated facilities should not require a GO to
also register as a Transmission Owner. The draft team has proposed modifying two
FAC standards that would apply to such GO-owned interconnection transmission
facilities. These GO-owned interconnection transmission facilities are not, however,
“integrated” transmission facilities, as the drafting team correctly points out in its
background resource document. A proposed solution to the Generation Owner
registration issue is discussed below.
NERC’s Rules of Procedure (ROP) require entities to be registered in accordance with
the definitions in the NERC Glossary of Terms Used in Reliability Standards (Glossary)
and in accordance with the NERC Statement of Compliance Registry Criteria document.
The Glossary has these definitions:
o Generation Owner - Entity that owns and maintains generating units.
o Transmission Owner - The entity that owns and maintains transmission
facilities.
o Facility - A set of electrical equipment that operates as a single Bulk Electric
System Element (e.g., a line, a generator, a shunt compensator, transformer,
etc.)
o Transmission - An interconnected group of lines and associated equipment for
the movement or transfer of electric energy between points of supply and points
at which it is transformed for delivery to customers or is delivered to other
electric systems.
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o Transmission Service - Services provided to the Transmission Customer by the
Transmission Service Provider to move energy from a Point of Receipt to a Point
of Delivery
The drafting team should create a new definition for the term “integrated transmission
facilities” and include this new definition in the Glossary. This definition should then be
use to modify the definition of Generation Owner so that registration will be clear.
While the team chose not to create any new definitions, we believe the registration
issue cannot be resolved without modifying the definition of “Generation Owner.”
The following definition is proposed for Integrated Transmission Facilities in the NERC
Glossary:
o Integrated Transmission Facilities (ITF) - ITF are the Facilities that are a subpart
of Transmission system that are capable of carrying the flows from multiple
generator plants at different points of interconnection for delivery to customers or
to other electric systems
This proposed ITF definition builds upon FERC precedent in the Open Access
Transmission Tariff (OATT) area. FERC has recognized that facilities that can carry
flows from multiple supply points and deliver that power to either customers or other
electric systems are proper facilities to include in an OATT and define the “Transmission
System” for OATT purposes. The term “Transmission System” is an OATT-defined term
that means “The facilities owned, controlled or operated by the Transmission Provider
that are used to provide transmission service under Part II [Point-to-Point Transmission
Service] and Part III [Network Integrated Transmission Service] of the Tariff.” Under
FERC’s precedent, facilities such as generator step-up transformers and generator
interconnecting transmission facilities have been excluded from the OATT; i.e., they are
not facilities that provide Transmission Service because they cannot carry the flows
from multiple supply points for delivery to customers or other electric system - their
only use is to the Generation Owner. They perform two functions for a GO:
1. They deliver power from the GO’s generators at a site to the OATT-defined
Transmission System, and
2. They deliver off-site power from the OATT-defined Transmission System to the
generators at a site when the generators at a site are not operating.
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While building on FERC OATT precedent, the proposed definition of “Integrated
Transmission Facilities” does not require an applicable Transmission Service tariff to
identify those facilities. Integrated Transmission Facilities are simply defined as those
that capable of carrying flows from multiple supply points for delivery to customers or
to other electric systems. Using the ITF definition, the definition of Generation Owner
could be modified as follows:
o Generation Owner - Entity that owns and maintains generating units but which
does not own or maintain Integrated Transmission Facilities.
Response: Thank you for your comment. We appreciate the detailed suggestions. While we are not proposing any definition
changes with this round of updated standard changes, we do plan to consider some definition changes or possibly new definitions to
prevent future registration and ensure that there are no possible gaps. In the next steps of our project, we will consider putting
forward definition-related changes for comment separately, as is now allowed by the Standards Committee after its July 2011
meeting.
EPSA
Yes
EPSA can appreciate the SDT’s decision that it not propose new defined terms for the
NERC Glossary. The SDT bases the decision on outreach meetings with NERC, regional
compliance managers and industry organizations. EPSA supports outreach but still
believes that the SDT should propose definitions for the NERC Glossary. The definitions
can serve as a basis for the outreach meetings while also further limiting reliability gaps
- real or perceived. Much as EPSA expressed in its White Paper comments there is still
a need for a definition for generator interconnection facilities. In addition, because
integrated transmission facility has also played a big part in the cases that have
prompted the need for Project 2010-07 the drafting team should propose a glossary
change for that definition as well. A definition for generation interconnection facilities is
necessary in Project 2010-07 Standard so that the interface between generators and
transmission system can be clearly established and any ambiguities about reliability
responsibilities for GOs & GOPs and TO & TOPs can be eliminated.
EPSA recommended the definitions from the Ad-Hoc Group Report could be used for
incorporating the Generator Interconnection Facility into the standard:
Generator Interconnection Facility - Sole-use facility for the purpose of connecting
the generating unit(s) to the transmission grid. In this regard, the sole-use facility
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only transmits power associated with the interconnecting generator, whether
delivered to the grid or delivered to the generator for station service or auxiliary
load, or delivered to meet cogeneration load requirements.
Generator Interconnection Operational Interface - Location at which operating
responsibility for the Generator Interconnection Facility changes between the
Transmission Operator and the Generator Operator.
These definitions were developed with due consideration for varying configurations,
outages, and generators materiality to the BES. The Facility definition defines the
purpose of the facility, while the Generator Interconnection Operational Interface
definition provides the functional lines of demarcation between the GO and the TO. The
definitions were developed based on the purpose of generator interconnection facilities,
their usage and how their usage differs from transmission facilities that comprise the
interconnected grid. Similar to EPSA’s assertions on the White Paper competitive
suppliers believe this is a sound basis for distinguishing BES facilities. EPSA also
suggests that the SDT include the following proposed definition for Integrated
Transmission Facilities for inclusion in the NERC Glossary:
Integrated Transmission Facilities (ITF) - ITF are the Facilities that are a subpart
of Transmission system that are capable of carrying the flows from multiple
generator plants at different points of interconnection for delivery to customers,
or to other electric systems.
This proposed ITF definition builds upon Commission precedent in the Open Access
Transmission Tariff (OATT) area. FERC has recognized that facilities that can carry
flows from multiple supply points and deliver that power to either customers or other
electric systems are proper facilities to include in an OATT and define the “Transmission
System” for OATT purposes. The term “Transmission System” is an OATT-defined term
that means “The facilities owned, controlled or operated by the Transmission Provider
that are used to provide transmission service under Part II [Point-to-Point Transmission
Service] and Part III [Network Integrated Transmission Service] of the Tariff.” Under
Commission precedent, facilities such as generator step-up transformers and generator
interconnecting transmission facilities have been excluded from the OATT; i.e., they are
not facilities that provide Transmission Service because they cannot carry the flows
from multiple supply points for delivery to customers or other electric system - their
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only use is to the GO and perform two functions:
1. They deliver power from the GO’s generators at a site to the OATT-defined
Transmission System, and
2. They deliver off-site power from the OATT-defined Transmission System to the
generators at a site when the generators at a site are not operating.
While building on FERC OATT precedent, the proposed definition of “Integrated
Transmission Facilities” does not require an applicable Transmission Service tariff to
identify those facilities. Integrated Transmission Facilities are simply defined as those
that capable of carrying flows from multiple supply points for delivery to customers or
to other electric systems. Using the ITF definition, the definition of Generation Owner
could be modified as follows:
Generation Owner - The Entity that owns and maintains generating units but
which does not own or maintain Integrated Transmission Facilities.
EPSA encourages the Project 2010-07 SDT to consider fitting the above definitions into
the current proposal for inclusion in the NERC Glossary. Therefore, EPSA respectfully
requests that the SDT for Project 2010-07 consider the all the recommendations made
herein to the seven questions.
Response: Thank you for your comment. We appreciate the detailed suggestions. While we are not proposing any definition
changes with this round of updated standard changes, we do plan to propose some definition changes or possibly new definitions to
prevent registration and ensure that there are no possible gaps. In the next steps of our project, we will consider putting forward
definition-related changes for comment separately, as is now allowed by the Standards Committee after its July 2011 meeting
PacifiCorp
Yes
PacifiCorp believes the Standards Drafting Team should clarify the Transmission Owner
and/or the Generator Owner are not required to provide evidence, documentation,
notification, or inspection of vegetation management for facilities not owned by the
Transmission Owner and/or the Generator Owner.
Response: Thank you for your comment. The drafting team does not know why a Transmission Owner or Generator Owner would
ever be required to provide evidence, documentation, notification, or inspection of vegetation management for Facilities not owned
by that registered entity, except where explicitly agreed upon in a contract. We do not believe this needs to be addressed within the
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Yes
(1) The SDT needs to review the June 16, 2011 FERC Order on Cedar Creek and Milford
and factor this into the equation. The FERC Order concludes that the Cedar Creek and
Milford entities must register as a TO and TOP. In addition to FAC-003, the Cedar
Creek and Milford order lists the following standards and requirements that apply to
these entities as a TO/TOP:
standard. No change made.
Southern Company
o PER-003-1, R1, R1.1, R1.2 (requiring NERC-certified transmission operators);
o PRC-001-1, R2, R2.2, R4, R6 (notification of relay or equipment failures);
o PRC-004-1, R1 (analyzing protection system misoperations);
o FAC-014-2, R2 (establishment of system operating limits);
o TOP-001, R1 (authority to take actions to alleviate operating emergencies);
o TOP-004-2, R6, R6.1, R6.2, R6.3, R6.4 (establishment of formal policies to
address voltage levels, planned outages, switching, Interconnection Reliability
Operating Limits, and System Operating Limits).
The SDT needs to address these specific requirements in sufficient detail by either
revising the Project 2010-07 Background Resource Document or proposing revisions to
these standards to address any reliability gaps. For example, we recommend, as a
minimum, that the Background Resource Document discussion under PRC-001-1 be
revised to state (underlined text added), “Generator Operators and the scope of
protection equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirements R1, R2, R3, and R5.” Please note that
this statement, even with our proposed revision, conflicts with the FERC Order on Cedar
Creek and Milford, Paragraphs 64, 65, and 78 where FERC states that Cedar Creek and
Milford must register as a TO and TOP to ensure the protection system coordination
requirements in R2 and R4 of PRC-001 are met. Thus, the discussion for PRC-001-1 in
the Project 2010-07 Background Resource Document needs additional language to
demonstrate adequacy of the GO requirements in order to prevent GOs that own
generation interconnection Facilities from having to register as a TO and TOP.
(2) In addition, we believe the SDT should add supporting discussion to the
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Background Resource Document to explain why the following standards adequately
cover GO/GOP requirements at the Transmission Interface: PRC-004-2, PRC-005-1,
PRC-023-1. For example, the Background Resource Document could state that PRC023-1 Section A.4 Applicability already includes, “4.2. Generator Owners with loadresponsive phase protection systems as described in Attachment A, applied to facilities
defined in 4.1.1 through 4.1.4.”
(3) Furthermore, FERC’s analysis in the Cedar Creek and Milford order suggests that
reliability gaps will occur if certain entities are not registered as TO/TOP. The GRTI SAR
DT should assess why its findings are different from the Commission’s findings. By way
of background, the GRTI SAR DT provides that its own assessment of the GOTO Ad Hoc
Group Final Report concludes with a belief that there are only two standards requiring
modifications to address reliability gaps - FAC-001 and FAC-003 (Background Resource
Document, page 3). FERC will most likely require that NERC clearly demonstrate and
provide technical support for the position that GO’s only need to comply with FAC-001
and FAC-003 and not the other standards noted by FERC. The Background Resource
Document does not appear to provide adequate technical support for the GRTI SAR DT
position. Therefore, the GRTI SAR DT should develop that technical support in
preparation for the filing of these revised standards at FERC.
Response: Thank you for your comment. We have considered the inclusion of additional standards and requirements throughout
our process and we continue to conclude, with stakeholder support, that no additional substantive standard or requirement changes
are necessary to achieve the goal of this project. With this posting, the drafting team has revisited those standards yet again and
developed a comprehensive document and spreadsheet tracing our rationale (at every stage of the process) for not including
additional standards or requirements. We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the
applicability of that or any other standard. We have attempted to make our technical justifications much more robust and
comprehensive than they were in the past, as you suggest. Please see the accompanying resource documents for more information.
APS
Yes
Leave GOs out of the standards, because it just adds more regulation and reporting
requirements not needed.
Response: Thank you for your comment. The drafting team and the majority of stakeholder commenters support making both
FAC-001 and FAC-003 applicable to Generator Owners to ensure that all Generator Owner responsibilities at the generator
interconnection Facility are covered under NERC Reliability Standards. No change made.
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Sempra Generation
Yes or
No
Question 7 Comment
Yes
When implemented, the recommendations of the Project 2010-07 Team go a long way
toward providing the regulatory and compliance certainty needed by generators who
own or operate Generator Interconnection Facilities. NERC is encouraged to provide
these industry-supported amendments to the NERC Board of Trustees in the near
future. Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment.
Exelon
Yes
FAC-001-1. Exelon has generating stations that have the Main Power Transformer
(MPT) disconnect as the point of demarcation. The station owns the short leads from
the MPT disconnect back to the generator and the applicable TO owns from the MPT
disconnect up to and including the switchyard. It is not practical for another entity to
request to interconnect to the MPT disconnect nor should it be allowed. The SDT
should consider verbiage to the standard that does not allow requests to interconnect
to a MPT disconnect. 2. Exelon is having difficulty determining how this standard would
apply to GOs and how GOs would implement the standard; suggest that examples be
provided in an implementation document specifically showing where and how this
standard would apply.
Response: Thank you for your comment.
(1) FAC-001-1 would not be “activated” simply with another entity’s request to interconnect. The standard is “activated” only with
an executed Agreement to evaluate the reliability impact of interconnection. If another entity cannot interconnect to the MPT, the
process should not get to the point of an executed Agreement and thus this standard would never apply.
(2) In the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have received or
have been directed to execute interconnection requests for their Facilities, and the drafting team thinks it is important to clarify the
responsibilities related to such a request in NERC’s Reliability Standards by including applicable Generator Owners in FAC-001-1. We
have documented our technical justification in an accompanying resource document and encourage you to review it.
Ingleside Cogeneration LP
Yes
Project 2010-07 Consideration of Comments
There is a fundamental issue related to the interconnection of generation and
distribution facilities into the transmission grid. There is a myriad of complex
architectures which make the designation of ownership and operational responsibilities
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unclear in both cases. Both this team’s efforts and those by the project team
redefining the extent of the BES have run into this issue.
Ingleside Cogeneration LP recognizes that the effort to properly assign reliability
responsibilities in these gray-area connections is difficult. However, pushing the issue
back to the GO/GOP by looking for them to jointly determine responsibilities with
adjacent entities will create every conceivable arrangement possible.
It seems like it should be possible to address a handful of common interconnection
configurations at the start. As knowledge builds, perhaps other architectures could be
added. This seems to be the direction that the project team redefining the extent of
the BES is heading.
Lastly, we need some assurance that regulators will work with us as we go down this
path. Right now, the feeling is that they will continue to use forced registrations as a
hammer - which may render moot this team’s efforts anyways.
Response: Thank you for your comment.
The drafting team is doing its best to coordinate with regulators to ensure that forced registrations no longer occur. While we can
never be sure exactly what decision the regulators will make, our intent is to make changes through this project that prevent any
future forced registrations. We have encouraged regulators to provide formal comments if they believe our changes are not going to
close the gap. While there can be similarities, the SDT believes that each interconnection agreement is different. The SDT believes
that each party to such agreement should have identified its ownership and operational responsibilities. If there is uncertainty as to
ownership of operational responsibility of a Facility used to interconnect a generator, the respective GO/GOPs and TO/TOPs should
be addressing these. Resolving these uncertainties can only occur between the affected parties.
Manitoba Hydro
Yes
Project 2010-07 Consideration of Comments
The direction of the background resource document gives special treatment to the
Generator Owner in that it allows the Generator Owner TO status for a couple of
standards (FAC-001 and FAC-003), but exempts the Generator Owner from many of
the standards applicable to a TO. A Generator Owner that owns BES transmission
should be held accountable for the specific Requirements and Reliability Standards
applicable to the TO and Transmission Operator functions. If no other entity assumes
accountability for these specific Requirements and Reliability Standards on the
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Generator Owner BES transmission (for example system operation, protection and
communication), there will be a reliability gap. Improper operation, coordination and
protection of the Generator Owner BES transmission could have an impact on reliability.
Response: Thank you for your comment. The purpose of the drafting team is “To propose a set of changes to existing
requirements and definitions, as well as additional requirements and definitions, that collectively adds significant clarity to
Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the interconnected
grid. This global strategy is proposed to expedite the closing of the reliability gap.” The SDT is applying select Transmission Owner
standards to Generator Owners, not attempting to give them TO status. The SDT believes that each interconnection agreement is
different. The SDT believes that each party to such agreement should have identified its ownership and operational responsibilities.
If there is uncertainty as to ownership of operational responsibility of a Facility used to interconnect a generator, the respective
GO/GOPs and TO/TOPs should be addressing these. Resolving these uncertainties can only occur between the affected parties.
Constellation Power
Generation
Yes
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The recent FERC Order concerning
Cedar Creek and Milford wind suggested that the list of applicable standards needing
revision should go beyond FAC-001 and FAC-003.
We appreciate the discussion and concerns raised by FERC in the order; however, the
discussion is limited by failing to consider these issues in light of the full package of
existing standards. Below is a look at the FERC suggested standards and how they
intersect with other standards:
o PRC-001-1, Requirements R2, R2.2, R4; FERC expressed concern that certain
protection system components may not be well coordinated with the RC.
However, the same standard (PRC-1) addresses this issue by requiring all GOs to
ensure coordination of their protection system with interconnected parties.
Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA,
etc.
o PRC-004-1 Requirement R1; FERC expressed concern that certain protection
system components may not be analyzed for misoperations. However, the same
standard (PRC-4) addresses this issue by requiring all GOs to ensure that they
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analyze all misoperations on their protection system which would include the
protection of the tie line.
o TOP-004-2, Requirements R6, R6.1, R6.2, R6.3, R6.4; FERC expressed concern
that coordination may be lacking between a GO and a TO with regards to the
generator tie line. However, TOP standards applicable to GOs address this issue
by requiring all GOs to coordinate all maintenance and emergency outages (both
forced and planned) with all applicable interconnected parties. Further, all ISO
procedures require the same of GOs.
o PER-003-1, Requirements R1, R1.1, R1.2; FERC expressed concern that certain
generator operators are responsible for the real time operation of the
interconnected BES without being NERC certified operators, potentially causing a
reliability gap. Generator Operators do not monitor and control the BES, they
control and monitor generators that it operates and relays information to other
operating entities. Therefore, NERC certification is not required.
o FAC-003-1, Requirements R1, R2; FERC and the drafting team seem aligned in
the need to revise this standard and the revision proposal includes such a
revision.
o TOP-001, Requirement R1; FERC expressed concern that certain tie lines may
not be required to operate in such a way as to alleviate operational emergencies.
However, IRO and TOP standards applicable to GOs address this issue by
requiring all GOs to operate as directed by their TOP, BA, or RC as directed and
must render emergency assistance.
o FAC-014-2, Requirement R2; FERC expressed concern that certain tie lines may
have a rating based on a methodology that may not be consistent with the
methodology used by the RC. However, standards FAC-8 and FAC-9 address this
issue by requiring all GOs to develop a methodology to rate all equipment, and
that the RC has the authority to challenge the GO on that methodology. The onus
is on the GO to either change their methodology and rating accordingly, or
provide a technical justification as to why they cannot adopt the changes. Further,
a generator will never be limited by its tie line, as a generator’s profits are
directly tied to its output. Therefore no generator would limit its facility to the
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equipment that is delivering that output.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements. We
appreciate the rationale you have included within your comment, and where we agree, we have incorporated it into our own.
We have elected to propose a slight clarifying change in PRC-004-2, but no changes to the applicability of that or any other
standard. Please see the accompanying resource documents for more information.
Utility Services, Inc.
Yes
In one of the supporting documents for the upcoming comments, the GO/TO group
included the following statement in support for the rationale on FAC-001. In its first
posting for informal comment, the drafting team set the “trigger” for the application of
FAC-001 as the receipt of a request for interconnection. Many commenters disagreed
with this approach and suggested that the “trigger” be based upon “the intent or
obligation” to interconnect a new Facility to an existing interconnecting Facility that is
owned by a generator. Accordingly, the drafting team has proposed language to
addresses this concern. The intent of this modified language is to start the compliance
clock at such time as the Generator Owner executes an Agreement to perform the
reliability assessment required in FAC-002-1. This step should occur whether the
generator voluntarily agrees to the interconnection request or is compelled by a
regulatory body to do so. In either case, we expect the Generator Owner and the
requestor to execute some form of Agreement. We intentionally excluded a specific
reference to the form of Agreement (such as a feasibility study) in deference to
comments that we should avoid comingling of commercial and reliability aspects in
reliability standards.
I wonder about whether or not this can work timing-wise. It says the compliance clock
starts with the agreement to perform the reliability assessment for FAC-002. The FAC001 requirements outline the need for a registered entity to document, maintain, and
publish facility connections requirements in order to be compliant. If the clock starts at
the agreement for the assessment, does that mean that you then document, maintain,
and publish the connection requirements? Don’t the connection requirements usually
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outline the terms for the “agreement for the assessment”? I am not sure that I
understand the timing sequence in order to be compliant to the standard. I would think
that the agreement needs to be in place at the time of the effective date of the
standard, not upon an application.
Response: Thank you for your comment. We have provided a detailed explanation of how this process might look in the
accompanying FAC-001-1 technical justification. Please refer to that for more information.
FirstEnergy Corp
Yes
The June 16, 2011 FERC Order denying the appeals of two wind generating facilitiesCedar Creek and Milford - of the NERC determinations that Cedar Creek and Milford
must each be registered as a transmission owner and transmission operator on the
NERC Compliance Registry complicates the GO-TO drafting team’s work. However, the
issues may be distinct and different in the end. The existing GO-TO team’s work
product defines new reliability expectations for a generator owner regardless of
whether or not the same entity is also being required to have a TO-TOP “light”
compliance registration. In the Order, FERC describes what it believes are an
appropriate limited set of TO-TOP requirements when a TO-TOP “light” registrations is
deemed warranted for a traditional generation owner. The drafting team should
describe what, if any, impact the FERC June 16 Order is having on its work scope.
One minor comment for the background resource document. On page one, the last
sentence of the 1st paragraph which currently reads “ ... appropriate level of reliability
for the BES.” Consider changing to read “ ... Adequate Level of Reliability for the BES.”
And, include a footnote directing the reader to NERC’s definition/paper describing ALR.
The later references to “adequate level of reliability” within the document (i.e. page 2,
2nd paragraph could then be reduced to the acronym ALR.
Response: Thank you for your comment. The drafting team has considered the inclusion of the requirements listed in the Cedar
Creek and Milford orders in the past, and we have been revisiting them throughout our process. We continue to conclude, with
stakeholder support, that no additional substantive standard or requirement changes are necessary to achieve the goal of this
project. With this posting, the drafting team has revisited those standards yet again and developed a comprehensive document and
spreadsheet tracing our rationale (at every stage of the process) for not including additional standards or requirements.
Thank you for pointing out the opportunity to use the term “Adequate Level of Reliability.” Because NERC has appointed a task force
to explore whether that definition of Adequate Level of Reliability needs to be changed, we are avoiding references to it in our latest
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resource document.
PPL Supply Group
Yes
American Wind Energy
Association
The American Wind Energy Association (AWEA) appreciates the opportunity to
submit these formal comments on the NERC Project 2010-07. AWEA supports the
general direction indicated by both the Generator Requirements at the Transmission
Interface Ad Hoc Group (GOTO Ad Hoc Group), and the Project 2010-07 Standards
Development Team (SDT). We agree with the sentiments from both groups that a
Generator Owner (GO) or Generator Operator (GOP) that also owns or operates a
generator interconnection facility (GIF), should not be required to register as a
Transmission Owner (TO) and/or Transmission Operator (TOP) strictly because they
own or operate the GIF. We also agree that requiring these GOs or GOPs to comply with
all the TO/TOP standards would have little effect on or benefits to reliability of the Bulk
Electric System.
AWEA supports the aim of these groups to address any reliability gap that may exist
with regard to GIFs by considering such facilities as part of the generating facility, and
therefore also subject to the GO/GOP standards. AWEA also supports the approach of
identifying a limited number of TO/TOP standards, such as FAC-001 and FAC-003,
which should also apply to GIFs. We would be concerned, however, if additional
requirements were added beyond these two, without serious consideration by the SDT
and additional industry experts. The recent FERC order on the required registration as
TOs and TOPs of two generator interconnection facilities may raise some question about
the direction that the GO/TO and the SDT have taken so far on this topic. AWEA urges
NERC and the SDT to use caution in considering any additional standards to apply to
GIFs as the current approach of the GO/TO and SDT efforts have been generally
supported. Consideration of any addition standards with respect to GIFs should be done
on a standard-by-standard basis, reviewing the applicability of each standard as well as
the impact on the reliability of the Bulk Electric System.
Response: Thank you for your comment. The drafting team has considered the inclusion of additional standards and requirements
in the past, and we have been revisiting them throughout our process. We continue to conclude, with stakeholder support, that no
Project 2010-07 Consideration of Comments
80
Organization
Yes or
No
Question 7 Comment
additional substantive standard or requirement changes are necessary to achieve the goal of this project. With this posting, the
drafting team has revisited those standards yet again and developed a comprehensive document and spreadsheet tracing our
rationale (at every stage of the process) for not including additional standards or requirements.
Cogeneration Association of
California
The resolution of this issue regarding generator interconnection facilities should compel a
certain result in determining how to classify and register generator tie-lines. Under the
current standards, NERC is compelled to register owners with generator tie-lines as
transmission owners. FERC has affirmed this. The changes to the standards should be
such that NERC and FERC are compelled to consider the tie-lines as part of the generator
facilities. The current proposal from this task force does not achieve that result. While
the proposal does make very appropriate changes to certain reliability standards, it does
not change the basic definition of the Bulk Electric System or change NERC’s Statement of
Compliance Registry Criteria, to determine how tie-lines are classified. Even though the
relevant reliability standards would be changed so that they are also applicable to
generator facilities, NERC and the regional entities will continue to apply the same
definition and criteria and can continue to classify the tie-lines as Transmission.
The solution is to change the BES definition and NERC Statement as well as changing the
applicability of the relevant reliability standards. The background resource document from
this group suggests that a change in the BES definition was part of the overall solution,
but the Project 2010-17 team did not address this in its proposed definition. The concept
paper from the 2010-17 group does include “generator interconnection line leads,” but the
formal definition paper does not.
This project group should include in its formal proposal a change to the definition of BES,
including generator interconnection facilities within the definition of generation.
Response: Thank you for your comment. While we are not proposing any definition changes with this round of updated standard
changes, we do plan to propose some definition changes or possibly new definitions to prevent registration and ensure that there
are no possible gaps. In the next steps of our project, we will consider putting forward definition-related changes for comment
separately, as is now allowed by the Standards Committee after its July 2011 meeting. Although this drafting team cannot itself
make changes to the Statement of Compliance Registry Criteria, our hope is that modifications to definitions would provide the
language and the impetus to make those Registry Criteria changes.
Project 2010-07 Consideration of Comments
81
Organization
Yes or
No
Question 7 Comment
While the Project 2010-07 SDT coordinated with the Project 2010-17 BES SDT very early on, the Project 2010-17 SDT elected not
to include any reference to generator interconnection Facilities within the definition of generation. We will consider making further
suggestions during future comment periods, and you should do the same.
American Electric Power
Tacoma Power
Indeck Energy Services
LG&E and KU Energy
American Transmission
Company
END OF REPORT
Project 2010-07 Consideration of Comments
82
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner within an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the Transmission System.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the Transmission System (under FAC002-1), document and publish its Facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Entity, subregional, Power Pool, and
individual Transmission Owner planning criteria and Facility connection requirements.
[VRF – Medium]
Draft 2: August 31, 2011
1 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection
requirements:
3.1. Provide a written summary of its plans to achieve the required system
performance as described in Requirements R1 or R2 throughout the planning
horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts
on the interconnected Transmission Systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission Systems)
as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
Draft 2: August 31, 2011
2 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System shall make available (to its Compliance Enforcement
Authority) evidence that it met all requirements stated in Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 2: August 31, 2011
3 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
R3 The responsible
entity’s Facility
The responsible
entity’s Facility
The responsible
entity’s Facility
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 2: August 31, 2011
4 of 5
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the Transmission
System.
The responsible
entity’s Facility
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
connection
requirements failed to
address one of the Parts
listed in Requirement
R3, Part 3.1.1 R3.1.6.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
connection
requirements failed to
address two of the
Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
connection
requirements failed to
address three of the
Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
connection
requirements failed
to address four or
more of the Parts
listed in
Requirement R3,
Part 3.1.1 R3.1.6.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date
Revision under Project
2010-07
Draft 2: August 31, 2011
5 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
The drafting team limited its
modifications to those associated
with expanding the scope to
include the Generator Owner and
bringing the format up to date.
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner within an executed Agreement to evaluate the reliability impact
of interconnecting another Facility to its existing generation Facilitya third party
Facility to the Generator Owner’s existing Facility that is used to interconnect to
the Transmission System.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the Transmission System of executing
an Agreement to evaluate the reliability impact of interconnecting another Facility to its
existing generation Facility (under FAC-002-1), shall document and publish its and thereafter
maintain Facility connection requirements to ensure compliance with NERC Reliability
Draft 12: June 17, 2011August 31, 2011
1 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
Standards and applicable Regional Entity, subregional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection requirements.
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) with Facility connection requirements and each Transmission Owner
shall have Facility connection requirements that address the following items in its
Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system
performance as described in Requirements R1 and or R2 throughout the planning
horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts
on the interconnected Transmission Systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission Systems)
as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System pProtection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shallEach applicable Generator Owner with Facility connection
requirements (in accordance with Requirement R2) and each Transmission Owner shall
maintain Facility connection requirements and maintain and update its Facility connection
Draft 12: June 17, 2011August 31, 2011
2 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements as required. The Transmission Owner shall make documentation of these
requirements available to the users of the tTransmission sSystem, the Regional Entity, and
ERO on request (five business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System that executes an Agreement to evaluate the reliability
impact of interconnecting another Facility to its existing generation Facility shall make
available (to its Compliance Enforcement Authority) evidence that it met all requirements
stated in Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) Each applicable Generator Owner with Facility connection requirements and
each Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all requirements stated in Requirement R3.
M4. Each applicable Generator Owner with Facility connection requirements and eachThe
Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
Draft 12: June 17, 2011August 31, 2011
3 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
High VSL
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Document or maintain requirements.
or publish its Facility
connection
requirements as
specified in the
Requirement
OR
OR
Failed to include one
(1) of the components
and as specified in
R1.1, R1.2 or R1.3.
Failed to include (2) of
the components as
specified in R1.1, R1.2
or R1.3
OR
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 12: June 17, 2011August 31, 2011
Severe VSL
4 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
R2 The responsible
entityGenerator Owner
failed to document and
publish and thereafter
maintain Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.executing an
Agreement to evaluate
the reliability impact of
interconnecting another
Facility to its existing
generation Facility.
The Generator Owner
responsible entity
failed to document and
publish and thereafter
maintain Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.executing an
Agreement to evaluate
the reliability impact of
interconnecting another
Facility to its existing
generation Facility.
The Generator Owner
responsible entity
failed to document and
publish and thereafter
maintain Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.executing an
Agreement to evaluate
the reliability impact
of interconnecting
another Facility to its
existing generation
Facility.
R3 The responsible
entity’s Facility
connection
requirements failed to
address one of the Parts
listed in Requirement
R3, Part 3.1.1
R3.1.6subrequirements.
The responsible
entity’s Facility
connection
requirements failed to
address two of the
Parts listed in
Requirement R3, Part
3.1.1
R3.1.6subrequirements.
The responsible
entity’s Facility
connection
requirements failed to
address three of the
Parts listed in
Requirement R3, Part
3.1.1 R3.1.6subrequirements.
The Generator
Owner responsible
entity failed to
document and
publish and
thereafter maintain
Facility connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the Transmission
System.executing an
Agreement to
evaluate the
reliability impact of
interconnecting
another Facility to
its existing
generation Facility.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the Parts
listed in
Requirement R3,
Part 3.1.1
R3.1.6subrequireme
nts.
OR
R4 The responsible entity
made the requirements
available more than
Draft 12: June 17, 2011August 31, 2011
The responsible entity
made the requirements
available more than 10
5 of 6
The responsible entity
made the requirements
available more than 20
The responsible
entity does not have
Facility connection
requirements.
The responsible
entity made the
requirements
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
five business days but
less than or equal to 10
business days after a
request.
E.
business days but less
than or equal to 20
business days after a
request.
business days less than
or equal to 30 business
days after a request.
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date
Revision under Project
2010-07
Draft 12: June 17, 2011August 31, 2011
6 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner within an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the Transmission System.
Effective Date:
April 1, 2005
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability OrganizationEntity, subregional, Power Pool, and individual Transmission Owner
planning criteria and Facility connection requirements. The Transmission Owner’s Facility
connection requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the Transmission Owner’s System
(under FAC-002-1), document and publish its Facility connection requirements to ensure
compliance with NERC Reliability Standards and applicable Regional Entity, subregional,
Draft 2: August 31, 20111Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
of 6
of
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
Power Pool, and individual Transmission Owner planning criteria and Facility connection
requirements.
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address, but are not limited to, the following items: in its
Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system
performance as described abovein Requirements R1 or R2 throughout the
planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts
on the interconnected Transmission Systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission Systems)
as soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
Draft 2: August 31, 20112Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
to the users of the transmission system, the Regional Reliability OrganizationEntity, and
NERCERO on request (five business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for
inspectionEnforcement Authority) evidence that it met all the requirements stated in
Reliability Standard FAC-001-0_Requirement R1.
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission OwnerSystem shall make available (to its Compliance
Monitor) for inspectionEnforcement Authority) evidence that it met all requirements stated in
Reliability Standard FAC-001-0_Requirement R2.
M3. TheEach Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Monitor) for inspectionEnforcement
Authority) evidence that it met all the requirements stated in Reliability Standard FAC-0010_R3Requirement R3.
M3.M4. The Transmission Owner shall make available (to its Compliance Enforcement
Authority) evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
Compliance Monitor: Regional Reliability Organization.Entity
1.2.
Compliance Monitoring Period and Reset TimeframeEnforcement Processes:
On request (five business days).
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
None specified.
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
Draft 2: August 31, 20113Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
High VSL
Severe VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
Draft 2: August 31, 20114Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the Transmission
System.
R3 The responsible
entity’s Facility
connection
requirements failed to
address one of the Parts
listed in Requirement
R3, Part 3.1.1 R3.1.6.
The responsible
entity’s Facility
connection
requirements failed to
address two of the
Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
The responsible
entity’s Facility
connection
requirements failed to
address three of the
Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 2: August 31, 20115Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
of 6
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the Transmission
System.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the Parts
listed in
Requirement R3,
Part 3.1.1 R3.1.6.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
of
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
E.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date
Revision under Project
2010-07
Draft 2: August 31, 20116Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
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Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
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Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
4.1. Regional Entity.
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead transmission line(s) that extends
greater than one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard up to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any
lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
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Standard FAC-003-X — Transmission Vegetation Management Program
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
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Standard FAC-003-X — Transmission Vegetation Management Program
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
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Standard FAC-003-X — Transmission Vegetation Management Program
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
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Standard FAC-003-X — Transmission Vegetation Management Program
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
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Standard FAC-003-X — Transmission Vegetation Management Program
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
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Standard FAC-003-X — Transmission Vegetation Management Program
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
smaller than its
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Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
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Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
Standard FAC-003-X — Transmission Vegetation Management Program
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
10 of 12
Draft 2: August 31, 2011
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
Standard FAC-003-X — Transmission Vegetation Management Program
R3
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
vegetation
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
11 of 12
Draft 2: August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
footer.
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
12 of 12
Draft 2: August 31, 2011
Revision under Project
2010-07
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
4.1. Regional Entity.
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead Facility transmission line(s) that
extends greater than one half mile or 1.609 kilometers beyond the fenced area
of the switchyard, generating station or generating substation generating
station switchyard up to the point of interconnection with the Transmission
systema Transmission Owner’s Facility and is operated at 200 kV and above
and any lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
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Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
4 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
5 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity for the Regional
Entityapproved by the ERO and FERC or other applicable government
authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
6 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
7 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
8 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
9 of 12
Draft 21: June 17, 2011August 31, 2011
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
Standard FAC-003-X — Transmission Vegetation Management Program
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
10 of 12
Draft 21: June 17, 2011August 31, 2011
hold appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
Standard FAC-003-X — Transmission Vegetation Management Program
R3
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
annual plan for
vegetation
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
11 of 12
Draft 21: June 17, 2011August 31, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
4. Added “Draft 3: November 17, 2005” to
footer.
X
May 16, 2011
Added Made standard applicable to certain
qualifying requirements for Generator
Owners and brought overall standard
format up to date
12 of 12
Draft 21: June 17, 2011August 31, 2011
Revision under Project
2010-07
Standard FAC-003-1X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
of
Standard FAC-003-1X — Transmission Vegetation Management Program
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Reliability Organizations (RROEntity (RE) and the North American
Electric Reliability Council (NERC).
Applicability:
4.1. Regional Entity.
4.1.4.2.
Applicable Transmission Owner.
4.2.Regional Reliability Organization.
4.2.1. This standard shall apply to allTransmission Owner that owns overhead
transmission lines operated at 200 kV and above and to any lower voltage
lines designated by the RRORE as critical to the reliability of the electric
system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead transmission line(s) that extends
greater than one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard up to the point of interconnection with the a
Transmission Owner’s Facility and is operated at 200 kV and above and any
lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.
2 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
5.
Effective Dates:
5.1.One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
B.Requirements
The TransmissionThere are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. TheEach applicable Transmission Owner or applicable Generator Owner, in the
TVMP, shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
of
Standard FAC-003-1X — Transmission Vegetation Management Program
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
4 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
The[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
The[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its RRORegional Entity, or the RRO’sRegional Entity’s designee, sustained transmission line
outages determined by the applicable Transmission Owner or applicable Generator Owner to
have been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the RRORegional Entity, or the RRO’sRegional Entity’s designee, certain
sustained transmission line outages caused by vegetation: (1) Vegetation-related
outages that result from vegetation falling into lines from outside the ROW that result
from natural disasters shall not be considered reportable (examples of disasters that
could create non-reportable outages include, but are not limited to, earthquakes, fires,
tornados, hurricanes, landslides, wind shear, major storms as defined either by the
applicable Transmission Owner or applicable Generator Owner or an applicable
regulatory body, ice storms, and floods), and (2) Vegetation-related outages due to
human or animal activity shall not be considered reportable (examples of human or
animal activity that could cause a non-reportable outage include, but are not limited to,
logging, animal severing tree, vehicle contact with tree, arboricultural activities or
horticultural or agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the RRORegional Entity, or the RRO’sRegional Entity’s designee,
shall include at a minimum: the name of the circuit(s) outaged, the date, time and
duration of the outage; a description of the cause of the outage; other pertinent
comments; and any countermeasures taken by the applicable Transmission Owner or
applicable Generator Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
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Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The RRORegional Entity shall report the outage information provided to it by applicable
Transmission Owner’sOwners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the RRORegional Entity as a result of any
of the reported outages.
[VRF – Lower]
C.
Measures
M1. TheEach applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. TheEach applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. TheEach applicable Transmission Owner or applicable Generator Owner has documentation
that the Transmission Owner implemented the work plan identified in Requirement 2.
M3. The Each applicable Transmission Owner or applicable Generator Owner has documentation
that it has supplied quarterly outage reports to the RRORegional Entity, or the RRO’sRegional
Entity’s designee, as identified in Requirement 3.
M4. The RRORegional Entity has documentation that it provided quarterly outage reports to
NERC as identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
RRO
NERC
6 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring Period and ResetEnforcement Processes:
One calendar Year
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
Five Years
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
The Transmission Owner shall demonstrate compliance through self-certification
submitted to the compliance monitor (RRO) annually that it meets the requirements of
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an onsite audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
None.
2.
Violation Severity Levels of Non-Compliance
2.1.Level 1:
2.1.1.The TVMP was incomplete in one of the requirements specified in any subpart
of Requirement 1, or;
2.1.2.Documentation of the annual work plan, as specified in Requirement 2, was
incomplete when presented to the Compliance Monitor during an on-site
audit, or;
2.1.3.The RRO provided an outage report to NERC that was incomplete and did not
contain the information required in Requirement 4.
2.2.Level 2:
7 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
2.2.1.The TVMP was incomplete in two of the requirements specified in any subpart
of Requirement 1, or;
2.2.2.The Transmission Owner was unable to certify during its annual self-certification
that it fully implemented its annual work plan, or documented deviations
from, as specified in Requirement 2.
2.2.3.The Transmission Owner reported one Category 2 transmission vegetationrelated outage in a calendar year.
2.3.Level 3:
2.3.1.The Transmission Owner reported one Category 1 or multiple Category 2
transmission vegetation-related outages in a calendar year, or;
2.3.2.The Transmission Owner did not maintain a set of clearances (Clearance 2), as
defined in Requirement 1.2.2, to prevent flashover between vegetation and
overhead ungrounded supply conductors, or;
2.3.3.The TVMP was incomplete in three of the requirements specified in any subpart
of Requirement 1.
2.4.Level 4:
2.4.1.The Transmission Owner reported more than one Category 1 transmission
vegetation-related outage in a calendar year, or;
2.4.2.The TVMP was incomplete in four or more of the requirements specified in any
subpart of Requirement 1.
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
8 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
of
Standard FAC-003-1X — Transmission Vegetation Management Program
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
9 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
of
Standard FAC-003-1X — Transmission Vegetation Management Program
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
R1.2.2
R1.2.2.1
R1.2.2.2
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
10 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
Draft 2: August 31, 2011
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
of
Standard FAC-003-1X — Transmission Vegetation Management Program
R1.3
R1.4
R1.5
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
For responsible
entities directly
entities directly
involving fewer
involving fewer
than 20 persons in than 20 persons in
the design and
the design and
implementation of implementation of
the TVMP, three
the TVMP, more
of those persons
than three of those
did not hold
persons did not
appropriate
hold appropriate
qualifications and
qualifications and
training to perform training to perform
their duties. For
their duties. For
responsible entities responsible entities
directly involving
directly involving
20 or more persons 20 or more persons
in the design and
in the design and
implementation of implementation of
the TVMP, more
the TVMP, more
than 10% up to
than 15% of those
(and including)
persons did not
15%of those
hold appropriate
persons did not
qualifications and
hold appropriate
training to perform
qualifications and
their duties.
training to perform
their duties.
N/A
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
N/A
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
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Effective Date: April 7, 2006
Draft 2: August 31, 2011
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Standard FAC-003-1X — Transmission Vegetation Management Program
R2
R3
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
OR
N/A
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
management.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
N/A
N/A
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Effective Date: April 7, 2006
Draft 2: August 31, 2011
N/A
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Standard FAC-003-1X — Transmission Vegetation Management Program
E.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
13 of 13Adopted by NERC Board of Trustees: February 7, 2006
Effective Date: April 7, 2006
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Revision under Project
2010-07
of
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 2: September 29, 2011
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 2: September 29, 2011
2
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 2: September 29, 2011
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
3
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 2: September 29, 2011
4
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project will
be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, the latest draft
of Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. Several scenarios that could play out based
on the order of the approval of these versions of the standards are addressed in the FAC-003-3
implementation plan.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection Facility
in the standard with as few other changes as possible.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1.
4.2.
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
Draft 2: September 29, 2011
5
FAC-003-3 — Transmission Vegetation Management
4.1.2.1.
Generator Owners that own generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1.
Each overhead transmission line
industry for reasons summarized as
operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
4.2.2.
Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3.
Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
4.2.4.
Each overhead transmission line
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1.
Overhead transmission lines that extend
Standard FAC-003-3, “transmission
greater than one mile or 1.609
line(s) and “applicable line(s) can
kilometers beyond the fenced area of
also refer to the generation Facilities
the generating switchyard and are:
as referenced in 4.3 and its
subsections.
4.3.1.1.
Operated at 200kV or higher; or
4.3.1.2.
Operated below 200kV identified as an element of an IROL under
NERC Standard FAC-014 by the Planning Coordinator.
4.3.1.3.
Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
Enforcement:
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 2: September 29, 2011
6
FAC-003-3 — Transmission Vegetation Management
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
Draft 2: September 29, 2011
7
FAC-003-3 — Transmission Vegetation Management
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
Draft 2: September 29, 2011
8
FAC-003-3 — Transmission Vegetation Management
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 2: September 29, 2011
9
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 2: September 29, 2011
10
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
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11
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
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12
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
Rationale
Inspections are used by applicable
Transmission Owners and applicable
R6. Each applicable Transmission Owner and
Generator Owners to assess the condition of
applicable Generator Owner shall perform
the entire ROW. The information from the
a Vegetation Inspection of 100% of its
assessment can be used to determine risk,
applicable transmission lines (measured in
determine future work and evaluate
units of choice - circuit, pole line, line
recently-completed work. This requirement
miles or kilometers, etc.) at least once per
sets a minimum Vegetation Inspection
calendar year and with no more than 18
frequency of once per calendar year but
calendar months between inspections on
with no more than 18 months between
the same ROW 6 [Violation Risk Factor:
inspections on the same ROW. Based upon
Medium] [Time Horizon: Operations
average growth rates across North America
Planning].
and on common utility practice, this
minimum frequency is reasonable.
Transmission Owners should consider local
6
environmental
factors
that could
When the applicable Transmission Owner or applicable Generatorand
Owner
is prevented from
performing
a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
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13
FAC-003-3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 2: September 29, 2011
14
FAC-003-3 — Transmission Vegetation Management
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
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15
FAC-003-3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Draft 2: September 29, 2011
16
FAC-003-3 — Transmission Vegetation Management
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 2: September 29, 2011
17
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
Violation Severity Level
Lower
Moderate
High
Severe
High
The responsible entity
failed to manage
vegetation in a manner
such that the responsible
entity had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
The responsible entity failed
to manage vegetation in a
manner such that the
responsible entity had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity failed to
manage vegetation in a manner
such that the responsible entity
had an encroachment into the
MVCD due to blowing
together of applicable lines and
vegetation located inside the
ROW that caused a vegetationrelated Sustained Outage.
The responsible entity failed to
manage vegetation in a manner
such that the responsible entity
had an encroachment into the
MVCD due to a grow-in that
caused a vegetation-related
Sustained Outage.
Medium
The responsible entity
failed to manage
vegetation in a manner
such that the responsible
entity had an
encroachment into the
MVCD observed in Realtime, absent a Sustained
Outage.
The responsible entity failed
to manage vegetation in a
manner such that the
responsible entity had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity failed to
manage vegetation in a manner
such that the responsible entity
had an encroachment into the
MVCD due to blowing
together of applicable lines and
vegetation located inside the
ROW that caused a vegetationrelated Sustained Outage.
The responsible entity failed to
manage vegetation in a manner
such that the responsible entity
had an encroachment into the
MVCD due to a grow-in that
caused a vegetation-related
Sustained Outage.
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
Lower
Draft 2: September 29, 2011
18
FAC-003-3 — Transmission Vegetation Management
R4
R5
R6
R7
Real-time
Operations
Planning
Operations
Planning
Operations
Planning
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
Medium
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
Medium
The responsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The responsible entity failed
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
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19
FAC-003-3 — Transmission Vegetation Management
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 2: September 29, 2011
20
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 2: September 29, 2011
21
FAC-003-3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line
solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is
incorporating the line into the interconnected electrical energy transmission network which will thereafter make the line subject to the
standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line solely for
local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is incorporating
the line into the interconnected electrical energy transmission network. In this special case the line upon acquisition was designated as
an element of an Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
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22
FAC-003-3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to
lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not
elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 2: September 29, 2011
23
FAC-003-3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner or Reliability Coordinator to protect an Interconnection may
cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner to manage vegetation and to the corresponding performance level of the
Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation related outages
that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or applicable Generator
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to
the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines operated at nominal voltage levels not listed
in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on the next highest nominal
voltage in the table to determine an acceptable distance.
Draft 2: September 29, 2011
24
FAC-003-3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to
the transmission system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the
competency of the applicable Transmission Owner or applicable Generator Owner in managing vegetation. There are many
acceptable approaches to manage vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner chooses to use will
generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 2: September 29, 2011
25
FAC-003-3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially
threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular
service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner employee who personally identifies such a threat in the field. Confirmation
could also be made by sending out an employee to evaluate a situation reported by a landowner.
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FAC-003-3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to ensure the proper communication
between field personnel and the control center to allow the control center to take the appropriate action until or as the vegetation threat
is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or other
preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners may have a danger tree identification program that identifies trees
for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an
immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance.
The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or applicable Generator
Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or applicable Generator Owner’s rights, or other
circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A
wide range of actions can be taken to address various situations. General considerations include:
Draft 2: September 29, 2011
27
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner is constrained from
performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner could consider location specific measures such as modifying the inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could
include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document and track the specific corrective
action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner may determine that more
frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as anticipated growth rates of
the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner may choose units such as: circuit,
pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates 2,000 miles of applicable transmission
lines this applicable Transmission Owner or applicable Generator Owner will be responsible for inspecting all the 2,000 miles of lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then
the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
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FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner is required to complete its an
annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the
transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner provide evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles of applicable
transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s annual plan, the
applicable Transmission Owner or applicable Generator Owner will be responsible completing those identified miles. If a applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan that does not put the transmission system
at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the calculation
to determine what percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan,
or 900 / 900 = 100% completed annual miles. If an applicable Transmission Owner or applicable Generator Owner only completed
875 of the total 1000 miles with no acceptable documentation for modification of the annual plan the calculation for failure to
complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual
plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a
major storm could require redirecting local resources away from planned maintenance. This situation may also include complying
with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan
provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full
extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
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FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable Transmission Owners
or applicable Generator Owners may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator Owner, evidence of successful annual work plan execution could consist
of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed
work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
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FAC-003-3 — Transmission Vegetation Management
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FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 2: September 29, 2011
32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 2: September 29, 2011
33
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 2: September 29, 2011
34
FAC-003-3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 2: September 29, 2011
35
FAC-003-3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 2: September 29, 2011
36
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
Draft 2: September 29, 2011
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
37
FAC-003-32 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Fourth draft of revised standard posted (June 17, 2010-July 17, 2010).
9. Fifth draft of revised standard posted (February 18, 2011-February 28, 2011)
10. Sixth draft of revised standard posted (September xx - 2011)
Proposed Action Plan and Description of Current Draft
This is the fourth posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the sixth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Anticipated Date
September 2011
Receive BOT approval
November 2011
Draft 26: August 14, 2011September 29, 2011
1
FAC-003-32 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
This standard becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval is required. Where no regulatory approval is required, the standard
becomes effective on the first calendar day of the first calendar quarter one year after Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
Draft 26: August 14, 2011September 29, 2011
2
FAC-003-32 — Transmission Vegetation Management
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 26: August 14, 2011September 29, 2011
3
FAC-003-32 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
23
April 4, 2007
September 29,
2011
Regulatory Approval — Effective Date New
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
Draft 26: August 14, 2011September 29, 2011
4
FAC-003-2 3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 26: August 14September 29, 2011
5
FAC-003-2 3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project will
be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, the latest draft
of Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. Several scenarios that could play out based
on the order of the approval of these versions of the standards are addressed in the FAC-003-3
implementation plan.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection Facility
in the standard with as few other changes as possible.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-32
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
4.1.1.1.
4.2.
Applicable Transmission Owners
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
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6
FAC-003-2 3 — Transmission Vegetation Management
4.1.2.1.
Generator Owners that own generation Facilities defined in 4.3
4.1.
4.1.1 Transmission Owners
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1.
4.2.1. Each overhead transmission line
industry for reasons summarized as
operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) NERC has a
project in place to address at a later date
the applicability of this standard to
Generation Owners. 34) Specifically
dd
i
h
h
h
d d
4.2.2.
4.2.2. Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3.
4.2.3. Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
4.2.4.
4.2.4. Each overhead transmission line
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.3.1.
Overhead transmission lines that extend
industry for reasons summarized as
greater than one mile or 1.609
follows: 1) There is a very low risk from
kilometers beyond the fenced area of
vegetation in this area. Based on an
the generating switchyard and are:
4.3.1.1.
Operated at 200kV or higher; or
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
4.3.1.2.
Operated below 200kV identified as an element of an IROL under
NERC Standard FAC-014 by the Planning Coordinator.
4.3.1.3.
Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 26: August 14September 29, 2011
7
FAC-003-2 3 — Transmission Vegetation Management
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
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8
FAC-003-2 3 — Transmission Vegetation Management
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
•5.1.7.
Performance-based: Requirements 1 and 2
•5.1.8.
Competency-based: Requirement 3
•5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
Draft 26: August 14September 29, 2011
9
FAC-003-2 3 — Transmission Vegetation Management
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 26: August 14September 29, 2011
10
FAC-003-2 3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of a an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner a Transmission Owner subject to this reliability standard, including natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by
the applicable Transmission Owner or applicable Generator Owner Transmission Owner or an applicable regulatory
body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with
tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner
Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within
the ROW, this shall be considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 26: August 14September 29, 2011
11
FAC-003-2 3 — Transmission Vegetation Management
and applicable Generator Owner Transmission Owner has evidence that it managed
vegetation to prevent encroachment into the MVCD as described in R1. Examples of
acceptable forms of evidence may include dated attestations, dated reports containing
no Sustained Outages associated with encroachment types 2 through 4 above, or
records confirming no Real-time observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner shall manage vegetation to prevent encroachments into the MVCD of its
applicable line(s) which are not either an element of an IROL, or an element of a Major
WECC Transfer Path; operating within its Rating and all Rated Electrical Operating
Conditions of the types shown below2 [Violation Risk Factor: Medium] [Time Horizon:
Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it managed vegetation to prevent encroachment into the
MVCD as described in R2. Examples of acceptable forms of evidence may include
dated attestations, dated reports containing no Sustained Outages associated with
encroachment types 2 through 4 above, or records confirming no Real-time
observations of any MVCD encroachments. (R2)
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12
FAC-003-2 3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner
The documentation provides a basis for
Transmission Owner shall have
evaluating the competency of the applicable
documented maintenance strategies or
Transmission Owner’s or applicable
procedures or processes or specifications
Generator Owner’s vegetation program.
it uses to prevent the encroachment of
There may be many acceptable approaches
vegetation into the MVCD of its
to maintain clearances. Any approach must
applicable lines that accounts for the
demonstrate that the applicable
following:
Transmission Owner or applicable
3.1 Movement of applicable line
Generator Owner Transmission Owner
conductors under their Rating and
avoids vegetation-to-wire conflicts under all
all Rated Electrical Operating
Ratings and all Rated Electrical Operating
Conditions;
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
Transmission Owner can prevent encroachment into the MVCD considering the factors
identified in the requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator
This is to ensure expeditious communication
OwnerTransmission Owner, without any
between the applicable Transmission Owner or
intentional time delay, shall notify the
applicable Generator Owner Transmission
control center holding switching
Owner and the control center when a critical
authority for the associated applicable
situation is confirmed.
line when the applicable Transmission
Owner and applicable Generator Owner Transmission Owner has confirmed the
existence of a vegetation condition that is likely to cause a Fault at any moment
[Violation Risk Factor: Medium] [Time Horizon: Real-time].
M4. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner that has a confirmed vegetation condition likely to cause a Fault at any moment
will have evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
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13
FAC-003-2 3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner
Transmission Owner is constrained from
performing vegetation work on an
applicable line operating within its Rating
and all Rated Electrical Operating
Conditions, and the constraint may lead to
a vegetation encroachment into the MVCD
prior to the implementation of the next
annual work plan, then the applicable
Transmission Owner or applicable
Generator OwnerTransmission Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner Transmission
Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner Transmission
Owner to put interim measures in place,
rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence of the corrective action taken for each constraint where an
applicable transmission line was put at potential risk. Examples of acceptable forms of
evidence may include initially-planned work orders, documentation of constraints from
landowners, court orders, inspection records of increased monitoring, documentation of
the de-rating of lines, revised work orders, invoices, or evidence that the line was deenergized. (R5)
Rationale
Inspections are used by applicable
Transmission Owners and applicable
Generator OwnersTransmission Owners to
R6. Each applicable Transmission Owner and
assess the condition of the entire ROW. The
applicable Generator Owner Transmission
information from the assessment can be
Owner shall perform a Vegetation
used to determine risk, determine future
Inspection of 100% of its applicable
work and evaluate recently-completed
work. This requirement sets a minimum
transmission lines (measured in units of
choice - circuit, pole line, line miles or
Vegetation Inspection frequency of once per
kilometers, etc.) at least once per calendar
calendar year but with no more than 18
year and with no more than 18 calendar
months between inspections on the same
months between inspections on the same
ROW. Based upon average growth rates
6
ROW [Violation Risk Factor: Medium]
across North America and on common
[Time Horizon: Operations Planning].
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
6
When the applicable Transmission Owner or applicable Generator Owner Transmission Owner is prevented from
performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a
Draft 26: August 14September 29, 2011
14
FAC-003-2 3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it conducted Vegetation Inspections of the transmission line
ROW for all applicable lines at least once per calendar year but with no more than 18
calendar months between inspections on the same ROW. Examples of acceptable forms
of evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner Transmission
Rationale
Owner shall complete 100% of its annual
This requirement sets the expectation
vegetation work plan of applicable lines to
that the work identified in the annual
ensure no vegetation encroachments occur
work plan will be completed as planned.
within the MVCD. Modifications to the
It allows modifications to the planned
work plan in response to changing
work for changing conditions, taking into
conditions or to findings from vegetation
consideration anticipated growth of
inspections may be made (provided they do
vegetation and all other environmental
not allow encroachment of vegetation into
factors, provided that those modifications
the MVCD) and must be documented. The
do not put the transmission system at risk
percent completed calculation is based on
of a vegetation encroachment.
the number of units actually completed
divided by the number of units in the final
amended plan (measured in units of choice - circuit, pole line, line miles or kilometers,
etc.) Examples of reasons for modification to annual plan may include [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
time extension that is equivalent to the duration of the time the TO or GO was prevented from performing the
Vegetation Inspection.
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes,
landslides, ice storms, floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 26: August 14September 29, 2011
15
FAC-003-2 3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it completed its annual vegetation work plan for its applicable
lines. Examples of acceptable forms of evidence may include a copy of the completed
annual work plan (as finally modified), dated work orders, dated invoices, or dated
inspection records. (R7)
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16
FAC-003-2 3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner
Transmission Owner retains data or evidence to show compliance with
Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and
M7 for three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The applicable Transmission Owner and applicable Generator Owner
Transmission Owner retains data or evidence to show compliance with
Requirement R4, Measure M4 for most recent 12 months of operator logs or most
recent 3 months of voice recordings or transcripts of voice recordings, unless
directed by its Compliance Enforcement Authority to retain specific evidence for
a longer period of time as part of an investigation.
If a applicable Transmission Owner or applicable Generator Owner Transmission
Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant or for the time period specified above,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
Draft 26: August 14September 29, 2011
17
FAC-003-2 3 — Transmission Vegetation Management
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions as determined by the applicable Transmission Owner or
applicable Generator Owner Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, and including as a minimum the
following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator OwnerTransmission
Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
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18
FAC-003-2 3 — Transmission Vegetation Management
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator OwnersTransmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional
Entity as a result of any of the reported Sustained Outages.
Draft 26: August 14September 29, 2011
19
FAC-003-2 3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
R2
R3
Time
Horizon
Real-time
Real-time
Long-Term
Planning
VRF
High
Medium
Violation Severity Level
Lower
Moderate
High
Severe
The Transmission
Ownerresponsible entity
failed to manage
vegetation in a manner
such that the responsible
entityTransmission Owner
had an encroachment into
the MVCD observed in
Real-time, absent a
Sustained Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a
manner such that the
responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a manner
such that the responsible entity
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a manner
such that the responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The responsible entity
Transmission Owner
failed to manage
vegetation in a manner
such that the responsible
entityTransmission Owner
had an encroachment into
the MVCD observed in
Real-time, absent a
Sustained Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a
manner such that the
responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a manner
such that the responsible
entityTransmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines and
vegetation located inside the
ROW that caused a vegetationrelated Sustained Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a manner
such that the responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a grow-in that caused a
vegetation-related Sustained
Outage.
The responsible entity
Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
The responsible entity
Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
The responsible entity
Transmission Owner does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
Lower
Draft 26: August 14September 29, 2011
20
FAC-003-2 3 — Transmission Vegetation Management
vegetation control methods,
and inspection frequency, for
the responsible entity’s
Transmission Owner’s
applicable lines. (Requirement
R3, Part 3.2)
R4
R5
Real-time
Operations
Planning
R6
Operations
Planning
R7
Operations
Planning
Medium
and all Rated Electrical
Operating Conditions, for the
responsible entity’s
Transmission Owner’s
applicable lines. Requirement
R3, Part 3.1)
responsible entity’s
Transmission Owner’s
applicable lines.
The responsible entity
Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity
Transmission Owner did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
Medium
The responsible entity
Transmission Owner
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The responsible entity
Transmission Owner failed to
inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
Transmission Owner failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
Transmission Owner failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The responsible entity
Transmission Owner
failed to complete 5% or
less of its annual
The responsible entity
Transmission Owner failed to
complete more than 5% and
up to and including 10% of its
The responsible entity
Transmission Owner failed to
complete more than 10% and
up to and including 15% of its
The responsible entity
Transmission Owner failed to
complete more than 15% of its
annual vegetation work plan for
Draft 26: August 14September 29, 2011
21
FAC-003-2 3 — Transmission Vegetation Management
vegetation work plan for
its applicable lines (as
finally modified).
annual vegetation work plan
for its applicable lines (as
finally modified).
annual vegetation work plan
for its applicable lines (as
finally modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 26: August 14September 29, 2011
22
its applicable lines (as finally
modified).
FAC-003-2 3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 26: August 14September 29, 2011
23
FAC-003-2 3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner Transmission Owner from a third party such as a Distribution Provider or other end-user who
was using the line solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator
OwnerTransmission Owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network
which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner Transmission Owner from a third party such as a Distribution Provider or other end-user who was using
the line solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator OwnerTransmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network. In this special case
the line upon acquisition was designated as an element of an Interconnection Reliability Operating Limit (IROL) or an element of a
Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 26: August 14September 29, 2011
24
FAC-003-2 3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner Transmission Owner to manage vegetation to prevent encroachment within the MVCD of transmission
lines. R1 is applicable to lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other
lines that are not elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 26: August 14September 29, 2011
25
FAC-003-2 3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner Transmission Operator or Reliability Coordinator to protect an
Interconnection may cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and
Rated Electrical Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner Transmission Owner to manage vegetation and to the corresponding performance
level of the Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading event. The
additional benefits of such a combination are that it simplifies the standard and clearly defines performance for compliance. A
performance-based requirement of this nature will promote high quality, cost effective vegetation management programs that will
deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner Transmission Owner has applicable lines operated at nominal
voltage levels not listed in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on
the next highest nominal voltage in the table to determine an acceptable distance.
Draft 26: August 14September 29, 2011
26
FAC-003-2 3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner Transmission Owner uses for vegetation
management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the transmission system. The approach provides the basis for evaluating the intent, allocation of
appropriate resources, and the competency of the applicable Transmission Owner or applicable Generator Owner Transmission Owner
in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages. However, the
applicable Transmission Owner or applicable Generator Owner Transmission Owner must be able to show the documentation of its
approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner Transmission
Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner Transmission Owner uses to
control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 26: August 14September 29, 2011
27
FAC-003-2 3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the
notification of potentially threatening vegetation conditions, without any intentional delay, to the control center holding switching
authority for that specific transmission line. Examples of acceptable unintentional delays may include communication system
problems (for example, cellular service or two-way radio disabled), crews located in remote field locations with no communication
access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 26: August 14September 29, 2011
28
FAC-003-2 3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner Transmission Owner has the responsibility to ensure the proper
communication between field personnel and the control center to allow the control center to take the appropriate action until or as the
vegetation threat is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of
service, or other preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should
be communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners Transmission Owners may have a danger tree identification program
that identifies trees for removal with the potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing
vegetation maintenance. The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner Transmission Owner from performing planned vegetation management work and, as a result, have the
potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from
legal injunctions filed by property owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the
transmission line. A wide range of actions can be taken to address various situations. General considerations include:
Draft 26: August 14September 29, 2011
29
FAC-003-2 3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner Transmission Owner is
constrained from performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner Transmission Owner could consider location specific measures such as modifying the
inspection and/or maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner Transmission Owner should document and track the
specific corrective action taken at each location. This location may be indicated as one span, one tree or a combination of
spans on one property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner Transmission Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as
anticipated growth rates of the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore
it is expected that some transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner Transmission Owner may choose
units such as: circuit, pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner Transmission Owner operates 2,000 miles of
applicable transmission lines this applicable Transmission Owner or applicable Generator Owner Transmission Owner will be
responsible for inspecting all the 2,000 miles of lines at least once during the calendar year. If one of the included lines was 100 miles
long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL”
for R6 would apply in this example.
Draft 26: August 14September 29, 2011
30
FAC-003-2 3 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner Transmission Owner is required
to complete its an annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work
plan in response to changing conditions or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even
a “line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner Transmission Owner provide evidence of annual planning and execution of a vegetation management
maintenance approach which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner Transmission Owner identifies 1,000 miles of
applicable transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s Transmission
Owner’s annual plan, the applicable Transmission Owner or applicable Generator Owner Transmission Owner will be responsible
completing those identified miles. If a applicable Transmission Owner or applicable Generator Owner Transmission Owner makes a
modification to the annual plan that does not put the transmission system at risk of an encroachment the annual plan may be modified.
If 100 miles of the annual plan is deferred until next year the calculation to determine what percentage was completed for the current
year would be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner Transmission Owner only completed 875 of the total 1000 miles with
no acceptable documentation for modification of the annual plan the calculation for failure to complete the annual plan would be:
1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner Transmission Owner to
change priorities or treatment methodologies during the year as conditions or situations dictate. For example recent line inspections
may identify unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the
plan year, or a major storm could require redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator
Owner’s Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach
that exercises the full extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 26: August 14September 29, 2011
31
FAC-003-2 3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner Transmission Owner
should allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some
cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners Transmission Owners may also need to consider those special landowner
requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator OwnerTransmission Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of
planned versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and
walk-through reports.
Draft 26: August 14September 29, 2011
32
FAC-003-2 3 — Transmission Vegetation Management
Draft 26: August 14September 29, 2011
33
FAC-003-2 3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, tThe applicable Transmission Owner or applicable Generator Owner
Transmission Owner should use the maximum system voltage to determine the appropriate clearance for that line.
Draft 26: August 14September 29, 2011
34
FAC-003-2 3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 26: August 14September 29, 2011
35
FAC-003-2 3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 26: August 14September 29, 2011
36
FAC-003-2 3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 26: August 14September 29, 2011
37
FAC-003-2 3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 26: August 14September 29, 2011
38
FAC-003-2 3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 26: August 14September 29, 2011
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
39
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 2: Revised November 9, 2011
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 2: Revised November 9, 2011
2
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 2: Revised November 9, 2011
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
3
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 2: September 29, 2011
4
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project will
be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, the latest draft
of Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. Several scenarios that could play out based
on the order of the approval of these versions of the standards are addressed in the FAC-003-3
implementation plan.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection Facility
in the standard with as few other changes as possible.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1.
4.2.
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
Draft 2: September 29, 2011
5
FAC-003-3 — Transmission Vegetation Management
4.1.2.1.
Generator Owners that own generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1.
Each overhead transmission line
industry for reasons summarized as
operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
4.2.2.
Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3.
Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
4.2.4.
Each overhead transmission line
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1.
Overhead transmission lines that extend
Standard FAC-003-3, “transmission
greater than one mile or 1.609
line(s) and “applicable line(s) can
kilometers beyond the fenced area of
also refer to the generation Facilities
the generating switchyard and are:
as referenced in 4.3 and its
subsections.
4.3.1.1.
Operated at 200kV or higher; or
4.3.1.2.
Operated below 200kV identified as an element of an IROL under
NERC Standard FAC-014 by the Planning Coordinator.
4.3.1.3.
Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
Enforcement:
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 2: September 29, 2011
6
FAC-003-3 — Transmission Vegetation Management
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
Draft 2: September 29, 2011
7
FAC-003-3 — Transmission Vegetation Management
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
Draft 2: September 29, 2011
8
FAC-003-3 — Transmission Vegetation Management
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 2: September 29, 2011
9
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 2: September 29, 2011
10
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 2: September 29, 2011
11
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 2: September 29, 2011
12
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
Rationale
Inspections are used by applicable
Transmission Owners and applicable
R6. Each applicable Transmission Owner and
Generator Owners to assess the condition of
applicable Generator Owner shall perform
the entire ROW. The information from the
a Vegetation Inspection of 100% of its
assessment can be used to determine risk,
applicable transmission lines (measured in
determine future work and evaluate
units of choice - circuit, pole line, line
recently-completed work. This requirement
miles or kilometers, etc.) at least once per
sets a minimum Vegetation Inspection
calendar year and with no more than 18
frequency of once per calendar year but
calendar months between inspections on
with no more than 18 months between
the same ROW 6 [Violation Risk Factor:
inspections on the same ROW. Based upon
Medium] [Time Horizon: Operations
average growth rates across North America
Planning].
and on common utility practice, this
minimum frequency is reasonable.
Transmission Owners should consider local
6
environmental
factors
that could
When the applicable Transmission Owner or applicable Generatorand
Owner
is prevented from
performing
a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 2: September 29, 2011
13
FAC-003-3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 2: September 29, 2011
14
FAC-003-3 — Transmission Vegetation Management
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
Draft 2: September 29, 2011
15
FAC-003-3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Draft 2: September 29, 2011
16
FAC-003-3 — Transmission Vegetation Management
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 2: September 29, 2011
17
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
On November 3, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management with NERC staff-proposed changes to the VSLs for R1 and R2 in lieu of the Project 200707 SDT’s original proposed VSLs. The table below now reflects the VSLs for R1 and R2 that were
approved by NERC’s Board of Trustees. The only additional change made by the Project 2010-07 SDT
was to change “Transmission Owner” to “responsible entity.”
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 2: September 29, 2011
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
18
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
FAC-003-3 — Transmission Vegetation Management
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R3
Long-Term
Planning
Lower
R4
Real-time
Medium
R5
Operations
Planning
Medium
Draft 2: September 29, 2011
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
19
FAC-003-3 — Transmission Vegetation Management
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
R6
R7
Operations
Planning
Operations
Planning
Medium
The responsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The responsible entity failed
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 2: September 29, 2011
20
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 2: September 29, 2011
21
FAC-003-3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line
solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is
incorporating the line into the interconnected electrical energy transmission network which will thereafter make the line subject to the
standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line solely for
local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is incorporating
the line into the interconnected electrical energy transmission network. In this special case the line upon acquisition was designated as
an element of an Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 2: September 29, 2011
22
FAC-003-3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to
lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not
elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 2: September 29, 2011
23
FAC-003-3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner or Reliability Coordinator to protect an Interconnection may
cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner to manage vegetation and to the corresponding performance level of the
Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation related outages
that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or applicable Generator
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to
the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines operated at nominal voltage levels not listed
in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on the next highest nominal
voltage in the table to determine an acceptable distance.
Draft 2: September 29, 2011
24
FAC-003-3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to
the transmission system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the
competency of the applicable Transmission Owner or applicable Generator Owner in managing vegetation. There are many
acceptable approaches to manage vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner chooses to use will
generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 2: September 29, 2011
25
FAC-003-3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially
threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular
service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner employee who personally identifies such a threat in the field. Confirmation
could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 2: September 29, 2011
26
FAC-003-3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to ensure the proper communication
between field personnel and the control center to allow the control center to take the appropriate action until or as the vegetation threat
is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or other
preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners may have a danger tree identification program that identifies trees
for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an
immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance.
The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or applicable Generator
Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or applicable Generator Owner’s rights, or other
circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A
wide range of actions can be taken to address various situations. General considerations include:
Draft 2: September 29, 2011
27
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner is constrained from
performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner could consider location specific measures such as modifying the inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could
include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document and track the specific corrective
action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner may determine that more
frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as anticipated growth rates of
the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner may choose units such as: circuit,
pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates 2,000 miles of applicable transmission
lines this applicable Transmission Owner or applicable Generator Owner will be responsible for inspecting all the 2,000 miles of lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then
the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 2: September 29, 2011
28
FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner is required to complete its an
annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the
transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner provide evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles of applicable
transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s annual plan, the
applicable Transmission Owner or applicable Generator Owner will be responsible completing those identified miles. If a applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan that does not put the transmission system
at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the calculation
to determine what percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan,
or 900 / 900 = 100% completed annual miles. If an applicable Transmission Owner or applicable Generator Owner only completed
875 of the total 1000 miles with no acceptable documentation for modification of the annual plan the calculation for failure to
complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual
plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a
major storm could require redirecting local resources away from planned maintenance. This situation may also include complying
with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan
provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full
extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 2: September 29, 2011
29
FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable Transmission Owners
or applicable Generator Owners may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator Owner, evidence of successful annual work plan execution could consist
of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed
work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 2: September 29, 2011
30
FAC-003-3 — Transmission Vegetation Management
Draft 2: September 29, 2011
31
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 2: September 29, 2011
32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 2: September 29, 2011
33
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 2: September 29, 2011
34
FAC-003-3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 2: September 29, 2011
35
FAC-003-3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 2: September 29, 2011
36
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
Draft 2: September 29, 2011
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
37
FAC-003-32 — Transmission Vegetation Management
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed
1. SC approved SAR for initial posting (January 11, 2007).
2. SAR posted for comment (January 15–February 14, 2007).
3. SAR posted for comment (April 10–May 9, 2007).
4. SC authorized moving the SAR forward to standard development (June 27, 2007).
5. First draft of proposed standard posted (October 27, 2008-November 25, 2008)).
6. Second draft of revised standard posted (September 10, 20-October 24, 2009).
7. Third draft of revised standard posted (March 1, 2010-March 31, 2010).
8. Fourth draft of revised standard posted (June 17, 2010-July 17, 2010).
9. Fifth draft of revised standard posted (February 18, 2011-February 28, 2011)
10. Sixth draft of revised standard posted (September xx - 2011)
Proposed Action Plan and Description of Current Draft
This is the fourth posting of the proposed revisions to the standard in accordance with ResultsBased Criteria and the sixth draft overall.
Future Development Plan
Anticipated Actions
Recirculation ballot of standards.
Anticipated Date
September 2011
Receive BOT approval
November 2011
Draft 26: August 14, 2011September 29November 3, 2011
1
FAC-003-32 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
This standard becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval is required. Where no regulatory approval is required, the standard
becomes effective on the first calendar day of the first calendar quarter one year after Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
Draft 26: August 14, 2011September 29November 3, 2011
2
FAC-003-32 — Transmission Vegetation Management
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 26: August 14, 2011September 29November 3, 2011
3
FAC-003-32 — Transmission Vegetation Management
Ve rs io n His to ry
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section
A, 5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
23
April 4, 2007
September 29,
2011
Regulatory Approval — Effective Date New
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
Draft 26: August 14, 2011September 29November 3, 2011
4
FAC-003-2 3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 26: August 14September 29, 2011
5
FAC-003-2 3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project will
be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, the latest draft
of Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. Several scenarios that could play out based
on the order of the approval of these versions of the standards are addressed in the FAC-003-3
implementation plan.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection Facility
in the standard with as few other changes as possible.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-32
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
4.1.1.1.
4.2.
Applicable Transmission Owners
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
Draft 26: August 14September 29, 2011
6
FAC-003-2 3 — Transmission Vegetation Management
4.1.2.1.
Generator Owners that own generation Facilities defined in 4.3
4.1.
4.1.1 Transmission Owners
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1.
4.2.1. Each overhead transmission line
industry for reasons summarized as
operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) NERC has a
project in place to address at a later date
the applicability of this standard to
Generation Owners. 34) Specifically
dd
i
h
h
h
d d
4.2.2.
4.2.2. Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3.
4.2.3. Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
4.2.4.
4.2.4. Each overhead transmission line
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.3.1.
Overhead transmission lines that extend
industry for reasons summarized as
greater than one mile or 1.609
follows: 1) There is a very low risk from
kilometers beyond the fenced area of
vegetation in this area. Based on an
the generating switchyard and are:
4.3.1.1.
Operated at 200kV or higher; or
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
4.3.1.2.
Operated below 200kV identified as an element of an IROL under
NERC Standard FAC-014 by the Planning Coordinator.
4.3.1.3.
Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 26: August 14September 29, 2011
7
FAC-003-2 3 — Transmission Vegetation Management
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
Draft 26: August 14September 29, 2011
8
FAC-003-2 3 — Transmission Vegetation Management
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
Draft 26: August 14September 29, 2011
9
FAC-003-2 3 — Transmission Vegetation Management
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 26: August 14September 29, 2011
10
FAC-003-2 3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of a an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner a Transmission Owner subject to this reliability standard, including natural disasters
such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by
the applicable Transmission Owner or applicable Generator Owner Transmission Owner or an applicable regulatory
body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with
tree, or installation, removal, or digging of vegetation. Nothing in this footnote should be construed to limit the
Transmission Owner’s right to exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner
Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within
the ROW, this shall be considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 26: August 14September 29, 2011
11
FAC-003-2 3 — Transmission Vegetation Management
and applicable Generator Owner Transmission Owner has evidence that it managed
vegetation to prevent encroachment into the MVCD as described in R1. Examples of
acceptable forms of evidence may include dated attestations, dated reports containing
no Sustained Outages associated with encroachment types 2 through 4 above, or
records confirming no Real-time observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner shall manage vegetation to prevent encroachments into the MVCD of its
applicable line(s) which are not either an element of an IROL, or an element of a Major
WECC Transfer Path; operating within its Rating and all Rated Electrical Operating
Conditions of the types shown below2 [Violation Risk Factor: Medium] [Time Horizon:
Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it managed vegetation to prevent encroachment into the
MVCD as described in R2. Examples of acceptable forms of evidence may include
dated attestations, dated reports containing no Sustained Outages associated with
encroachment types 2 through 4 above, or records confirming no Real-time
observations of any MVCD encroachments. (R2)
Draft 26: August 14September 29, 2011
12
FAC-003-2 3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner
The documentation provides a basis for
Transmission Owner shall have
evaluating the competency of the applicable
documented maintenance strategies or
Transmission Owner’s or applicable
procedures or processes or specifications
Generator Owner’s vegetation program.
it uses to prevent the encroachment of
There may be many acceptable approaches
vegetation into the MVCD of its
to maintain clearances. Any approach must
applicable lines that accounts for the
demonstrate that the applicable
following:
Transmission Owner or applicable
3.1 Movement of applicable line
Generator Owner Transmission Owner
conductors under their Rating and
avoids vegetation-to-wire conflicts under all
all Rated Electrical Operating
Ratings and all Rated Electrical Operating
Conditions;
3.2 Inter-relationships between vegetation growth rates, vegetation
control methods, and inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
Transmission Owner can prevent encroachment into the MVCD considering the factors
identified in the requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator
This is to ensure expeditious communication
OwnerTransmission Owner, without any
between the applicable Transmission Owner or
intentional time delay, shall notify the
applicable Generator Owner Transmission
control center holding switching
Owner and the control center when a critical
authority for the associated applicable
situation is confirmed.
line when the applicable Transmission
Owner and applicable Generator Owner Transmission Owner has confirmed the
existence of a vegetation condition that is likely to cause a Fault at any moment
[Violation Risk Factor: Medium] [Time Horizon: Real-time].
M4. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner that has a confirmed vegetation condition likely to cause a Fault at any moment
will have evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 26: August 14September 29, 2011
13
FAC-003-2 3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner
Transmission Owner is constrained from
performing vegetation work on an
applicable line operating within its Rating
and all Rated Electrical Operating
Conditions, and the constraint may lead to
a vegetation encroachment into the MVCD
prior to the implementation of the next
annual work plan, then the applicable
Transmission Owner or applicable
Generator OwnerTransmission Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner Transmission
Owner from performing planned vegetation
maintenance work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner Transmission
Owner to put interim measures in place,
rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence of the corrective action taken for each constraint where an
applicable transmission line was put at potential risk. Examples of acceptable forms of
evidence may include initially-planned work orders, documentation of constraints from
landowners, court orders, inspection records of increased monitoring, documentation of
the de-rating of lines, revised work orders, invoices, or evidence that the line was deenergized. (R5)
Rationale
Inspections are used by applicable
Transmission Owners and applicable
Generator OwnersTransmission Owners to
R6. Each applicable Transmission Owner and
assess the condition of the entire ROW. The
applicable Generator Owner Transmission
information from the assessment can be
Owner shall perform a Vegetation
used to determine risk, determine future
Inspection of 100% of its applicable
work and evaluate recently-completed
work. This requirement sets a minimum
transmission lines (measured in units of
choice - circuit, pole line, line miles or
Vegetation Inspection frequency of once per
kilometers, etc.) at least once per calendar
calendar year but with no more than 18
year and with no more than 18 calendar
months between inspections on the same
months between inspections on the same
ROW. Based upon average growth rates
6
ROW [Violation Risk Factor: Medium]
across North America and on common
[Time Horizon: Operations Planning].
utility practice, this minimum frequency is
reasonable. Transmission Owners should
consider local and environmental factors
6
When the applicable Transmission Owner or applicable Generator Owner Transmission Owner is prevented from
performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a
Draft 26: August 14September 29, 2011
14
FAC-003-2 3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it conducted Vegetation Inspections of the transmission line
ROW for all applicable lines at least once per calendar year but with no more than 18
calendar months between inspections on the same ROW. Examples of acceptable forms
of evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner Transmission
Rationale
Owner shall complete 100% of its annual
This requirement sets the expectation
vegetation work plan of applicable lines to
that the work identified in the annual
ensure no vegetation encroachments occur
work plan will be completed as planned.
within the MVCD. Modifications to the
It allows modifications to the planned
work plan in response to changing
work for changing conditions, taking into
conditions or to findings from vegetation
consideration anticipated growth of
inspections may be made (provided they do
vegetation and all other environmental
not allow encroachment of vegetation into
factors, provided that those modifications
the MVCD) and must be documented. The
do not put the transmission system at risk
percent completed calculation is based on
of a vegetation encroachment.
the number of units actually completed
divided by the number of units in the final
amended plan (measured in units of choice - circuit, pole line, line miles or kilometers,
etc.) Examples of reasons for modification to annual plan may include [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
time extension that is equivalent to the duration of the time the TO or GO was prevented from performing the
Vegetation Inspection.
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes,
landslides, ice storms, floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 26: August 14September 29, 2011
15
FAC-003-2 3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner Transmission
Owner has evidence that it completed its annual vegetation work plan for its applicable
lines. Examples of acceptable forms of evidence may include a copy of the completed
annual work plan (as finally modified), dated work orders, dated invoices, or dated
inspection records. (R7)
Draft 26: August 14September 29, 2011
16
FAC-003-2 3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner
Transmission Owner retains data or evidence to show compliance with
Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and
M7 for three calendar years unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
The applicable Transmission Owner and applicable Generator Owner
Transmission Owner retains data or evidence to show compliance with
Requirement R4, Measure M4 for most recent 12 months of operator logs or most
recent 3 months of voice recordings or transcripts of voice recordings, unless
directed by its Compliance Enforcement Authority to retain specific evidence for
a longer period of time as part of an investigation.
If a applicable Transmission Owner or applicable Generator Owner Transmission
Owner is found non-compliant, it shall keep information related to the noncompliance until found compliant or for the time period specified above,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
Draft 26: August 14September 29, 2011
17
FAC-003-2 3 — Transmission Vegetation Management
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner Transmission Owner will submit a quarterly report to its
Regional Entity, or the Regional Entity’s designee, identifying all Sustained
Outages of applicable lines operated within their Rating and all Rated Electrical
Operating Conditions as determined by the applicable Transmission Owner or
applicable Generator Owner Transmission Owner to have been caused by
vegetation, except as excluded in footnote 2, and including as a minimum the
following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator OwnerTransmission
Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
Draft 26: August 14September 29, 2011
18
FAC-003-2 3 — Transmission Vegetation Management
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator OwnersTransmission Owners, as
per the above, quarterly to NERC, as well as any actions taken by the Regional
Entity as a result of any of the reported Sustained Outages.
Draft 26: August 14September 29, 2011
19
FAC-003-2 3 — Transmission Vegetation Management
Table of Compliance Elements
On November 3, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation Management with
NERC staff-proposed changes to the VSLs for R1 and R2 in lieu of the Project 2007-07 SDT’s original proposed
VSLs. Those latest changes are reflected here. The only additional change made by the Project 2010-07 SDT
was to change “Transmission Owner” to “responsible entity” in both sets of VSLs.
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
Moderate
High
Severe
The Transmission
Ownerresponsible entity
failed to manage
vegetation in a manner
such that the responsible
entityTransmission Owner
had an encroachment into
the MVCD observed in
Real-time, absent a
Sustained Outage.
The responsible entity
Transmission Owner failed to
manage vegetation in a
manner such that the
responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.The
responsible entity Transmission
Owner failed to manage
vegetation in a manner such
that the responsible entity
Transmission Owner had an
encroachment into the MVCD
due to blowing together of
applicable lines and vegetation
located inside the ROW that
caused a vegetation-related
Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
High
Draft 26: August 14September 29, 2011
20
•
A grow-inThe responsible
entity Transmission Owner
failed to manage vegetation
in a manner such that the
responsible entity
Transmission Owner had
an encroachment into the
MVCD due to a grow-in
FAC-003-2 3 — Transmission Vegetation Management
that caused a vegetationrelated Sustained Outage.
The responsible entity
Transmission Owner
failed to manage
vegetation in a manner
such that the responsible
entityTransmission Owner
had an encroachment into
the MVCD observed in
Real-time, absent a
Sustained Outage.
R2
R3
Real-time
Long-Term
Planning
The responsible entity
Transmission Owner failed to
manage vegetation in a
manner such that the
responsible entity
Transmission Owner had an
encroachment into the MVCD
due to a fall-in from inside the
ROW that caused a
vegetation-related Sustained
Outage.
Medium
Lower
Draft 26: August 14September 29, 2011
The responsible entity
Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.The
responsible entity Transmission
Owner failed to manage
vegetation in a manner such
that the responsible
entityTransmission Owner had
an encroachment into the
MVCD due to blowing
together of applicable lines and
vegetation located inside the
ROW that caused a vegetationrelated Sustained Outage.
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
The responsible entity
Transmission Owner has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
The responsible entity
Transmission Owner does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
21
•
A grow-inThe responsible
entity Transmission Owner
failed to manage vegetation
in a manner such that the
responsible entity
Transmission Owner had
an encroachment into the
MVCD due to a grow-in
that caused a vegetationrelated Sustained Outage.
FAC-003-2 3 — Transmission Vegetation Management
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
Transmission Owner’s
applicable lines. (Requirement
R3, Part 3.2)
R4
R5
Real-time
Operations
Planning
Medium
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s
Transmission Owner’s
applicable lines. Requirement
R3, Part 3.1)
the encroachment of vegetation
into the MVCD, for the
responsible entity’s
Transmission Owner’s
applicable lines.
The responsible entity
Transmission Owner
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
Transmission Owner
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity
Transmission Owner did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
R6
Operations
Planning
Medium
The responsible entity
Transmission Owner
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
R7
Operations
Planning
Medium
The responsible entity
Transmission Owner
Draft 26: August 14September 29, 2011
The responsible entity
Transmission Owner failed to
inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
Transmission Owner failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
Transmission Owner failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
Transmission Owner failed to
The responsible entity
Transmission Owner failed to
The responsible entity
Transmission Owner failed to
22
FAC-003-2 3 — Transmission Vegetation Management
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 26: August 14September 29, 2011
23
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
FAC-003-2 3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 26: August 14September 29, 2011
24
FAC-003-2 3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner Transmission Owner from a third party such as a Distribution Provider or other end-user who
was using the line solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator
OwnerTransmission Owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network
which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner Transmission Owner from a third party such as a Distribution Provider or other end-user who was using
the line solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator OwnerTransmission
owner, upon acquisition, is incorporating the line into the interconnected electrical energy transmission network. In this special case
the line upon acquisition was designated as an element of an Interconnection Reliability Operating Limit (IROL) or an element of a
Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 26: August 14September 29, 2011
25
FAC-003-2 3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner Transmission Owner to manage vegetation to prevent encroachment within the MVCD of transmission
lines. R1 is applicable to lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other
lines that are not elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 26: August 14September 29, 2011
26
FAC-003-2 3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner Transmission Operator or Reliability Coordinator to protect an
Interconnection may cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and
Rated Electrical Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner Transmission Owner to manage vegetation and to the corresponding performance
level of the Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading event. The
additional benefits of such a combination are that it simplifies the standard and clearly defines performance for compliance. A
performance-based requirement of this nature will promote high quality, cost effective vegetation management programs that will
deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner Transmission Owner has applicable lines operated at nominal
voltage levels not listed in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on
the next highest nominal voltage in the table to determine an acceptable distance.
Draft 26: August 14September 29, 2011
27
FAC-003-2 3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner Transmission Owner uses for vegetation
management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained
Outages and minimize risk to the transmission system. The approach provides the basis for evaluating the intent, allocation of
appropriate resources, and the competency of the applicable Transmission Owner or applicable Generator Owner Transmission Owner
in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages. However, the
applicable Transmission Owner or applicable Generator Owner Transmission Owner must be able to show the documentation of its
approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner Transmission
Owner chooses to use will generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner Transmission Owner uses to
control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 26: August 14September 29, 2011
28
FAC-003-2 3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the
notification of potentially threatening vegetation conditions, without any intentional delay, to the control center holding switching
authority for that specific transmission line. Examples of acceptable unintentional delays may include communication system
problems (for example, cellular service or two-way radio disabled), crews located in remote field locations with no communication
access, delays due to severe weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner Transmission Owner’s employee who personally identifies such a threat in the
field. Confirmation could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 26: August 14September 29, 2011
29
FAC-003-2 3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner Transmission Owner has the responsibility to ensure the proper
communication between field personnel and the control center to allow the control center to take the appropriate action until or as the
vegetation threat is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of
service, or other preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should
be communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners Transmission Owners may have a danger tree identification program
that identifies trees for removal with the potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing
vegetation maintenance. The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner Transmission Owner from performing planned vegetation management work and, as a result, have the
potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from
legal injunctions filed by property owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner Transmission Owner is not under any immediate time constraint for achieving the management
objective, can easily reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the
transmission line. A wide range of actions can be taken to address various situations. General considerations include:
Draft 26: August 14September 29, 2011
30
FAC-003-2 3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner Transmission Owner is
constrained from performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner Transmission Owner could consider location specific measures such as modifying the
inspection and/or maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner Transmission Owner should document and track the
specific corrective action taken at each location. This location may be indicated as one span, one tree or a combination of
spans on one property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner Transmission Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as
anticipated growth rates of the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore
it is expected that some transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner Transmission Owner may choose
units such as: circuit, pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner Transmission Owner operates 2,000 miles of
applicable transmission lines this applicable Transmission Owner or applicable Generator Owner Transmission Owner will be
responsible for inspecting all the 2,000 miles of lines at least once during the calendar year. If one of the included lines was 100 miles
long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL”
for R6 would apply in this example.
Draft 26: August 14September 29, 2011
31
FAC-003-2 3 — Transmission Vegetation Management
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner Transmission Owner is required
to complete its an annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work
plan in response to changing conditions or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even
a “line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner Transmission Owner provide evidence of annual planning and execution of a vegetation management
maintenance approach which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner Transmission Owner identifies 1,000 miles of
applicable transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s Transmission
Owner’s annual plan, the applicable Transmission Owner or applicable Generator Owner Transmission Owner will be responsible
completing those identified miles. If a applicable Transmission Owner or applicable Generator Owner Transmission Owner makes a
modification to the annual plan that does not put the transmission system at risk of an encroachment the annual plan may be modified.
If 100 miles of the annual plan is deferred until next year the calculation to determine what percentage was completed for the current
year would be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner Transmission Owner only completed 875 of the total 1000 miles with
no acceptable documentation for modification of the annual plan the calculation for failure to complete the annual plan would be:
1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner Transmission Owner to
change priorities or treatment methodologies during the year as conditions or situations dictate. For example recent line inspections
may identify unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the
plan year, or a major storm could require redirecting local resources away from planned maintenance. This situation may also include
complying with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator
Owner’s Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach
that exercises the full extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 26: August 14September 29, 2011
32
FAC-003-2 3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner Transmission Owner
should allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some
cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners Transmission Owners may also need to consider those special landowner
requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator OwnerTransmission Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of
planned versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and
walk-through reports.
Draft 26: August 14September 29, 2011
33
FAC-003-2 3 — Transmission Vegetation Management
Draft 26: August 14September 29, 2011
34
FAC-003-2 3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, tThe applicable Transmission Owner or applicable Generator Owner
Transmission Owner should use the maximum system voltage to determine the appropriate clearance for that line.
Draft 26: August 14September 29, 2011
35
FAC-003-2 3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 26: August 14September 29, 2011
36
FAC-003-2 3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 26: August 14September 29, 2011
37
FAC-003-2 3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 26: August 14September 29, 2011
38
FAC-003-2 3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 26: August 14September 29, 2011
39
FAC-003-2 3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 26: August 14September 29, 2011
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
40
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity.
Au g u s t 31, 2011
1 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation Protection System shall each
retain data on its Protection System Misoperations and each accompanying Corrective
Action Plan until the Corrective Action Plan has been executed or for 12 months,
whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
3
XX
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
Revision under Project
2010-07
Au g u s t 31, 2011
2 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
The first day of the first calendar quarter, one year after applicable regulatory
approval; or in those jurisdictions where no regulatory approval is required, the first day of the
first calendar quarter one year after Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Au g u s t 31, 2011
1 of 3
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.1. Compliance Enforcement Authority
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation Protection System shall each
retain data on its Protection System Misoperations and each accompanying Corrective
Action Plan until the Corrective Action Plan has been executed or for 12 months,
whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
3
XX
Errata change: Edited R2 to add “…and
Revision under Project
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Au g u s t 31, 2011
2 of 3
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
generator interconnection Facility…”
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Au g u s t 31, 2011
2010-07
3 of 3
Implementation Plan for FAC-001-1—Facility
Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired at midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify one existing requirement (now R3)). Therefore, this implementation plan only
identifies a compliance timeframe for Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Implementation Plan for FAC-001-1 – —
Facility Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired whenat midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify twoone existing requirementsrequirement (now R3 and R4)). Therefore, this
implementation plan only identifies a compliance timeframe for Generator Owners to which this
standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Implementation Plan for FAC-003-3—
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC glossary upon approval of FAC-003-3, or the above definition of
Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at midnight the
day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has been
approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on order in which regulatory authorities approved FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming (as is required by
FAC-003-3 Requirement 1.3). Once a complete inventory is created, the Generator Owner will begin
the process of gathering information for the TVMP. In instances where the generation interconnection
Facilities are owned by a partnership, a majority or operating partner will need to obtain partnership
Implementation Plan for FAC-003-3
2
approval to proceed with procurement of a TVMP expert, and later a tree trimming crew. Typically, a
request for proposal to hire TVMP consultant is initiated which could take several weeks in order to
obtain sufficient bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received,
a contract with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator Owner
staff and the TVMP consultant will need to perform a Right-of-Way inspection (as required in FAC-0033 Requirement 1), usually done using GPS, LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-003-3
Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation (as required in FAC-003-3
Requirement 1.2). On an ongoing basis, in addition to performing inspections and clearances as
required by the entity's TVMP, the Generator Owner will need to ensure that the training and
qualification requirements for the standard are met. The entity will also need to maintain
documentation of all FAC-003-3 activities for compliance period of one year to meet compliance with
the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
Implementation Plan for FAC-003-3
3
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
Implementation Plan for FAC-003-3
4
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
5
Implementation Plan for FAC-003-3 –—
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 – Vegetation
Management must be implementedthat would affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard can). Generator Owners will be implementedrequired to comply with the implementation
plan as outlined below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired
whenat midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
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construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC glossary upon approval of FAC-003-3, or the above definition of
Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at midnight the
day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has been
approved.
Compliance with Standard
There are no changes toAs outlined above under “Prerequisite Approvals,” the requirements applicable
to inclusion of Transmission Owners already proposed in this implementation plan will depend on order
in which regulatory authorities approved FAC-003-2, and the expectation is that Transmission Owners
will maintain their current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to Version 2 of the standard only address Generator Owner applicability and
requirements (add Generator Owner to sections 4.1.2 and 4.FAC-003-3 and add applicable Generator
Owner to all requirements).. Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
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Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming (as is required by
FAC-003-3 Requirement 1.3). Once a complete inventory is created, the Generator Owner will begin
the process of gathering information for the TVMP. In instances where the generation interconnection
Facilities are owned by a partnership, a majority or operating partner will need to obtain partnership
approval to proceed with procurement of a TVMP expert, and later a tree trimming crew. Typically, a
request for proposal to hire TVMP consultant is initiated which could take several weeks in order to
obtain sufficient bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received,
a contract with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator Owner
staff and the TVMP consultant will need to perform a Right-of-Way inspection (as required in FAC-0033 Requirement 1), usually done using GPS, LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-003-3
Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation (as required in FAC-003-3
Requirement 1.2). On an ongoing basis, in addition to performing inspections and clearances as
required by the entity's TVMP, the Generator Owner will need to ensure that the training and
qualification requirements for the standard are met. The entity will also need to maintain
documentation of all FAC-003-3 activities for compliance period of one year to meet compliance with
the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are threetwo effective dates associated with this implementation plan:
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The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements applied to the Transmission Owner become effective upon
Board of Trustees’ adoption.
The second effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption.
The thirdsecond effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees adoption.
Exceptions:
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or asdesignated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being subjectan element of an IROL or an element of a Major
WECC Transfer Path, or 2) January 1 of the planning year when the line is forecast to this
standard.become an element of an IROL or an element of a Major WECC Transfer Path.
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2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher thatwhich is newly acquired by an
asset owner and which was not previously subject to this standard, becomes subject to this
standard 12 months after the acquisition date of the line..
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
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Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired at midnight the day before FAC-003-X becomes effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
1
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMP and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
3
Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired whenat midnight the day before FAC-003-2X becomes
effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
1
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMP and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
3
Implementation Plan for PRC-004-2.1—
Analyis of Transmission and Generation
Protection System Misoperations
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-004-2 will
be retired when PRC-004-2.1 becomes effective.
Compliance with Standard
The proposed change to Requirement R2 is a clarifying change. While there was no reliability gap in the
previous version of the standard, if applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection System
Misoperations, exclusive of its generator interconnection Facility. The errata change to R2 makes clear
that generator interconnection Facilities are also part of Generator Owners’ responsibility in the
context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption.
Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. The majority of these standards and requirements had been
addressed in the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface (Ad Hoc Report), and additional standards have been reviewed, and will continued to be
reviewed, as a result of informal discussions with NERC and FERC staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby radial interconnection Facilities
(at or above 100 kV) that are owned and operated by generating entities will be included in a small set
of standards and requirements previously only applicable to Transmission Owners. The SDT agrees
completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these radial
generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be registered as
Transmission Owners and Transmission Operators in order to maintain reliability on the Bulk Electric
System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate radial Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, would require
substantially more data and modeling responsibilities, and would detract from the entities’ primary
functions: to own and operate their generation equipment – including any Facilities owned and
operated at voltages of 100 kV or greater that connect to the interconnected system – in a reliable
manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document). While this applies to a specific NERC
Recommendation, the SDT considers this compelling evidence that the paradigm for thinking about
generator interconnection Facilities is shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004. The SDT
does not believe any further modifications to standards are necessary to maintain an appropriate level
of reliability based on the revised assumption that while generator Facilities (at 100 kV and above) will
be considered by some to be transmission, Generator Owners and Generator Operators should not be
registered as Transmission Owners and Transmission Operators simply as a result of the ownership and
operation of such Facilities. Because the majority of commenters support the SDT’s current
recommendation to not adopt new terms, the SDT has elected to focus on its standard changes and to
postpone discussions on revisions to existing, or creation of new, definitions until the standards have
been successfully balloted.
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and then
provides justification for not modifying any additional standards that had been proposed for
substantive modification in the Ad Hoc Report.
Review of SDT’s Proposed Standard Changes
Project 2010-07 Technical Justification Document
2
FAC-001-1—Facility Connection R equirem ents
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that
a regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation M anagem ent
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). After reviewing
formal comments, the SDT agreed to revise the exclusion so that it applies to a Facility if its length is
“one mile or 1.609 kilometers beyond the fenced area of the generating station switchyard” to
approximate line of sign from a fixed point. Other than revising this exclusion, the SDT applied the
same criteria to the Generator Owner as applies to the Transmission Owner in the current FERC
approved version of this standard as well as one approved by stakeholders (under Project 2007-07) in
February 2011. The SDT is communicating with NERC staff and the Project 2007-07 SDT to ensure that
changes to this standard will be coordinated before submitting to NERC’s Board of Trustees, but feels
compelled to continue to posting both versions until the outcome of Project 2007-07 efforts is clearer.
PR C-004-2.1—Analysis and M itigation of Transm ission and Generation Protection System
M isoperations
Project 2010-07 Technical Justification Document
3
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
Review of Other Substantive Standard Modifications from the Ad Hoc Report
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. Below, the SDT provides its reasons for not proposing the substantive changes
that were included in the Ad Hoc Report (that is, a change in applicability or new requirement, beyond
simply adding the text “including its Generator Interconnection Facility” to an existing requirement).
As Project 2010-07 continues, the SDT will work with FERC staff, NERC staff, and industry groups to
determine if its list of proposed standards is supported industry-wide, and whether other standards
need to be considered.
EOP-003-1—Load Shedding Plans
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
infers that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
IR O-005-2—Reliability Coordination – Current Day Operations
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially arrived at this decision because of the planned retirement of IRO-005-2. In
subsequent meetings, the SDT also reached the conclusion that there is no reliability gap as PRC-001-1
R2 already requires the Generator Operator to notify reliability entities of relay or equipment failures.
Project 2010-07 Technical Justification Document
4
The SDT believes that a Special Protection System is a form of protection system and therefore any
degradation or potential failure to operate as expected would be required to be reported by the
Generator Operator to reliability entities (Balancing Authorities, Transmission Operators, and
Reliability Coordinators).
Personnel Perform ance, Training, and Qualifications (PER) Standards
The SDT also chose not to propose the revisions to PER-001-0—Operating Personnel Responsibility
and Authority or PER-002-0—Operating Personnel Training that were proposed by the Ad Hoc Group.
For PER-001-0, the Ad Hoc Group had proposed adding a new R2 that would read “Each Generator
Operator shall provide operating personnel with the responsibility and authority to implement realtime actions to ensure the stable and reliable operation of the Generation Facility and Generation
Interconnection Facility, and the responsibility and authority to follow the directives of reliability
authorities including the Transmission Operator and Balancing Authority.” To PER-002-0, the Ad Hoc
Group proposed adding the Generator Operator to R1 (“Each Transmission Operator, Generator
Operator, and Balancing Authority shall be staffed with adequately trained operating personnel”) and
adding a new R3 that would read: “Each Generator Operator shall implement an initial and continuing
training program for all operating personnel that are responsible for operating the Generator
Interconnection Facility that verifies the personnel’s ability and understanding to operate the
equipment in a reliable manner.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities."
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed change to PER-002-0 and Order 742. Generator Operators who
deal with interconnection facilities at individual generating plants, on the other hand, typically do not
receive reliability-based orders specific to the interconnection Facilities and are therefore not covered
by Order 742. Further, the SDT believes there is no reliability gap as Generator Operators are, under
Project 2010-07 Technical Justification Document
5
currently approved reliability standards, required to follow directives issued by a Balancing Authority,
Reliability Coordinator or Transmission Operator.
These items are clearly important ones for the Commission, but the SDT does not think it is appropriate
to fold modifications to these PER standards into the scope of its work until it is specifically directed to
do so. For now, modifications to PER-002-0 based on Order 693 directives are already included in
NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is not addressed in the
Issues Database, but the Project 2007-03 drafting team has proposed that the standard be retired.
Transm ission Operations (TOP) Standards
For TOP standards, the Ad Hoc Group proposed a number of new requirements that the SDT does not
see as supportive of reliability. This set of standards was somewhat difficult to analyze, as the Project
2007-03—Real-time Transmission Operations drafting team has made significant changes to TOP-001
through TOP-008, resulting in three proposed TOP standards where are currently eight (see the
project’s Implementation Plan). The Project 2010-07 reviewed both the FERC-approved TOP standards
and the fifth draft of the modified standards in Project 2007-03 to determine whether it needed to
propose any additional changes to cover radial generator interconnection Facilities. In addition, the
Project 2010-07 SDT contacted the Project 2010-07 to get its opinion as to whether there might be any
reliability gaps related to generator interconnection facilities. No such changes will be proposed for the
reasons outlined below.
The Ad Hoc Group proposed adding two new requirements to TOP-001-1—Reliability Responsibilities
and Authority. The first was proposed as R9 and read: “The Generator Operator shall coordinate the
operation of its Generator Interconnection Facility with the Transmission Operator to whom it
interconnects in order to preserve Interconnection reliability…” The SDT does not agree that this
change is necessary. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined in
Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
Project 2010-07 Technical Justification Document
6
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
The Ad Hoc Group also proposed a new requirement, R7, for TOP-004-2—Transmission Operations
that would read: “The Generator Operator shall operate its Generator Interconnection Facility within
its applicable ratings.” The SDT does not agree that a reliability gap exists, because an operator has a
fiduciary obligation to protect a Facility for which it is operationally responsible. FAC-008-1—Facility
Ratings Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that
the reason for establishing a ratings methodology and communicating facility ratings to the Reliability
Coordinator, Planning Authority, Transmission Planner, and Transmission Operator is “…for use in
reliable planning and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be
retired under the work of the Project 2007-03 drafting team. Its requirements will either be deleted or
assigned elsewhere.
The Ad Hoc team proposed to add a new requirement, R5, to TOP-008-1—Response to Transmission
Limit Violations that would read “The Generator Operator shall disconnect the Generator
Interconnection Facility when safety is jeopardized or the overload or abnormal voltage or reactive
condition persists and generating equipment or the Generator Interconnection Facility is endangered.
In doing so, the Generator Operator shall notify its Transmission Operator and Balancing Authority
impacted by the disconnection prior to switching, if time permits, otherwise, immediately thereafter.”
The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each Transmission
Operator and Generator Operator shall not remove Bulk Electric System facilities from service if
removing those facilities would burden neighboring systems unless…”) and its parts give the Generator
Operator authority over its Facilities, which would include the generator interconnection Facility. If
there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
deleting all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
radial interconnection Facilities. The changes to FAC-001 and FAC-003 (and now PRC-004) have been
supported by stakeholders during comment periods, and there has been no strong support for bringing
other standards into the scope of this project.
Project 2010-07 Technical Justification Document
7
That said, the SDT recognizes the success of its work depends on stakeholders, NERC, and FERC
agreeing that generator requirements at the transmission interface are covered under NERC Reliability
Standards, both for the sake of reliability and to prevent further unwarranted registration of Generator
Owners and Generator Operators as Transmission Owners and Transmission Operators. If the SDT’s
work does not close the gap in the eyes of all parties, that work will have been unsuccessful, so the SDT
is considering all feedback it receives with request to this project. While it is posting changes to only
FAC-001, FAC-003, and PRC-004, and stands by that decision, it will continue to consider whether
glossary term additions/modifications and modifications to other standards could enhance the
reliability impact of this project. Based on conversations with NERC and FERC staff, and review of
FERC’s Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind
Corridor Phase I (135 FERC ¶ 61,241), the SDT is discussing whether it should consider the following
requirements for further review: EOP-005-1 R1, R2, R6, R7; FAC-014-2 R2; PER-003-1 R1, R1.1, R1.2;
PRC-001-1 R2, R2.2, R4, R6; PRC-004-1 R1; TOP-001 R1; TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4; and TOP006-1 R3. The SDT is actively seeking stakeholder feedback as to whether, in light of these orders, it
should consider additional standards and or new or modifications to existing definitions as it proceeds
with its work.
Project 2010-07 Technical Justification Document
8
Technical Justification: FAC-001-1
Project 2010-07 Generator Requirements at the Transmission Interface
In response to the June 17-July 17, 2011 formal posting of the proposed standard changes in Project
2010-07, the standard drafting team (SDT) received stakeholder comments on FAC-001-1 expressing
concern about the feasibility of a Generator Owner receiving and executing an interconnection request
on one of its interconnection Facilities, as well as concern about the market-related processes that
would go along with such an interconnection request. In this technical justification document, the SDT
seeks to further clarify its rationale for making the proposed FAC-001-1 applicable to qualifying
Generator Owners.
While the SDT understands that interconnection requests for Generator Owner Facilities are still
relatively rare, in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their
Facilities. The SDT acknowledges that FERC does not have jurisdiction over all Generator Owners, but
realizes that the potential exists for a third party to request to interconnect its planned generator with
an existing generator interconnection Facility (whose use at the time of the request is solely to
transmit capacity, energy, and ancillary services from the existing generator).
The SDT discussed the various ways such an interconnection could occur and agrees that if the third
party interconnection could be accomplished without the need for the existing Generator Owner to
develop its own connection requirements and system performance requirements and determine
impacts on the interconnected transmission systems, this standard need not apply to the Generator
Owner. And the SDT agrees that in many cases, these connection requirements, system performance
requirements, and determined impacts on the interconnected transmission systems are currently
determined by entities registered as either a Transmission Owner, Transmission Planner, and/or
Transmission Service Provider. However, the SDT remains convinced (based on the orders cited above)
that there may be occasions where FERC or another regulatory agency compels the Generator Owner
to allow a third party to interconnect its planned generator with an existing generator interconnection
Facility. Where this occurs, the SDT feels it is necessary for the existing owner of that generator
interconnection Facility to provide connection requirements to the third party that requests
interconnection. The SDT also believes, and many comments seem to support, that performance
requirements and a determination of impact to the interconnected transmission systems need to be
evaluated by some entity. The question becomes which entity.
The SDT can only work within the standards development process. We cannot address other regulatory
issues such as FERC-mandated open transmission access (Order 888 and subsequent) or state or
provincial jurisdiction over generation or transmission assets. While we acknowledge these
mechanisms exists and may come into play in the scenarios described in the proposed FAC-001-1, we
as the SDT can only deal within the context of reliability standards. For this reason, R2 indicates that
FAC-001-1 applies only when a Generator Owner has an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility.
The SDT’s reasoning here is that if the owner of the existing generator interconnection Facility agrees,
or is compelled, to allow a third party to interconnect, and can do so using existing agreements,
contracts, and/or tariffs (and thereby avoid having an executed Agreement to evaluate the reliability
impact of interconnecting third party Facility to the Generator Owner’s existing Facility), and thus avoid
having to develop its own connection requirements or perform impact studies, it will. In this example,
it is likely that the existing Transmission Owner, Transmission Planner, and/or Transmission Service
Provider processes and Agreements will be utilized and the purpose of FAC-001-1 will be met without
applying this standard to the Generator Owner.
If, on the other hand, the owner of the existing generator interconnection Facility agrees, or is
compelled, to allow a third party to interconnect, but cannot do so without having to develop its own
connection requirements or perform impact studies, the SDT believes that the potential for a reliability
gap exists. This might occur, for instance, if the owner of an existing generator interconnection Facility
was compelled to allow interconnection and to implement open transmission access. In this example,
(under FERC Order 888 and subsequent orders), the existing interconnection owner becomes a
Transmission Service Provider and is required to have an Open Access Transmission Tariff (OATT).
FERC’s pro forma OATT requires the Transmission Service Provider to, among other things, perform
system impact and feasibility studies. In order to do so, such studies must be coordinated with other
Transmission Service Providers and Transmission Planners. And, to further complicate the issue, the
SDT has been informed that in Texas, a Generator Owner is not allowed to own transmission.
Clearly, these issues are complex and not all are within the jurisdiction of federal or provincial
regulators. For these reasons, the SDT took the only approach it found workable. If, and only if, the
existing owner of a generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply. The SDT believes that this is most likely to occur if the owner of an existing
generator interconnection Facility is compelled to allow a third party to interconnect and adopt open
transmission access. However, the SDT cannot be certain this is the only example and it therefore
proposes to add this new requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third party to interconnect,
have the necessary expertise to conduct the required interconnect studies to meet this standard.
However, the SDT believes that, upon executing such Agreement, the Generator Owner will have to
acquire such expertise. How the Generator Owner chooses to do so is not for the SDT to determine.
The SDT is tasked with identifying potential reliability gaps and addressing such gaps through the
standards development process.
Project 2010-07 Technical Justification for FAC-001-1
2
The SDT does agree with many comments asking that the Generator Owner not be required to
maintain its connection requirements, and there was robust discussion among the team and observers.
Some were concerned that, without an obligation to maintain, there would not be a review to ensure
compliance with NERC Reliability Standards and applicable Regional Entity, subregional, Power Pool,
and individual Transmission Owner planning criteria. Others were concerned that the third party
requesting interconnection might not actually interconnect, but the owner of the existing generator
interconnection Facility would, having executed an evaluation agreement, be forever obligated to
maintain connection requirements. In the end, the SDT agreed that if the owner of the existing
generator interconnection Facility adopted open access or was determined to be providing
“transmission service” it was likely that its existing registration would be re-evaluated and that the
issue would be more appropriately addressed at that time. The SDT has therefore agreed to remove
maintenance requirements for Generator Owners from both Requirement R2 and Requirement R4 in
the proposed FAC-001-1.
We hope that you have found this explanation of our rationale helpful, but if you have further
suggestions for improvement or clarity, please submit them in your comments on this latest posting.
Project 2010-07 Technical Justification for FAC-001-1
3
Unofficial Comment Form
Generator Requirements at the Transmission Interface (Project 2010-07)
Please DO NOT use this form to submit comments. Please use the electronic comment form to
submit comments on the first formal posting for Project 2010-07—Generator Requirements at the
Transmission Interface. The electronic comment form must be completed by November 18, 2011.
2010-07 Project Page
If you have questions please contact Mallory Huggins at mallory.huggins@nerc.net or 202-3832629.
Background
With the exception of the errata change to PRC-004-2.1, which is being posted for the first time,
this is the second formal comment period and first ballot period for the standards included in
Project 2010-07. The standards will be posted for formal comment for 45-days, with a ballot during
the final 10 days of the comment period. Ballot pool formation will take place during the first 30
days of the comment period, and the SDT is hosting an interactive webinar on October 6.
A 30-day formal comment period took place earlier this year, from June 17-July 17, 2011. The SDT
thanks all those who provided feedback during that comment period. The SDT has reviewed and
considered all comments submitted, and has incorporated many of them into its latest proposed
standards, as explained in the Consideration of Comments form posted at the Project 2010-07
project page.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator
Operators operate Elements and Facilities that are considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to Transmission Owners and Transmission
Operators who own and operate Transmission Elements and Facilities that are part of the
integrated grid.
As part of the BES, generators affect the overall reliability of the BES. However, registering a
Generator Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has
been the solution in some cases in the past, may decrease reliability by diverting the Generator
Owner’s or Generator Operator’s resources from the operation of the equipment that actually
produces electricity – the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES
by clearly describing which standards need to be applied to generator interconnection Facilities that
are not already applicable to Generator Owners or Generator Operators. The SDT believes this can
be accomplished by properly applying FAC-001, FAC-003, and PRC-004-2.1 to Generator Owners
as proposed in the redline standards posted for comment.
NOTE: The Project 2007-07 Vegetation Management team will likely be posting a sixth draft of
FAC-003-2 for recirculation ballot during the Project 2010-07’s comment period. Both teams
acknowledge this overlap, and have been in contact to discuss best strategies moving forward. The
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
1
changes proposed by the Project 2010-07 SDT in FAC-003-3 are minimal, and serve only to apply
the standard and its requirements to qualifying Generator Owners. The SDT recognizes that a
number of scenarios may occur with respect to the filing and approval of Versions 2 and 3 of FAC003 and has attempted to account for those in the FAC-003-3 implementation plan.
You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.)
Yes
No
Comments:
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1?
Yes
No
Comments:
3. With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003.
Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one
mile beyond the fenced area of the generating station switchyard…” We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point
(at the fenced area of the generation station switchyard) eliminates confusion and any
discretion on the part of a Generator Owner or an auditor. Finally, we maintain that it is
appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary
to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented,
a decision that will be made as Project 2007-07—Vegetation Management moves forward, do
you support the proposed redline changes to FAC-003-X and FAC-003-3?
Yes
No
Comments:
4. Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X?
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
2
Yes
No
Comments:
5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here.
Yes
No
Comments:
6. In its technical justification document, the SDT reviews all standards that had been proposed
for substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Yes
No
Comments:
7. The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the
set of standards currently posted achieve this goal?
Yes
No
Comments:
8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting
the appropriate ones?
Yes
No
Comments:
9. If you answered “no” to Question 7, what standards need to be added or removed to achieve
the SDT’s goal? Please provide technical justification for your answer.
Yes
No
Comments:
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
3
10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Yes
No
Comments:
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
4
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Ballot Pool Forming October 5 – November 4, 2011
Formal Comment Period October 5 – November 18, 2011
Initial Ballot Windows Open November 9 – 18, 2011
Available Now
The SDT has reviewed comments received during a 30-day formal comment period that took place
earlier this year, from June 17-July 17, 2011, and thanks to all those who provided feedback during that
comment period. The SDT has incorporated many of the suggested changes into its latest proposed
standards, as explained in the posted Consideration of Comments.
This is the second formal comment period and initial ballot period for three standards included in
Project 2010-07. Revised drafts of FAC-001-1 and two versions of FAC-003 – FAC-003-3 and FAC-003-X –
along with minor modifications to PRC-004-2.1, have been posted for a formal comment period and
initial ballot that will end on Friday, November 18, 2011. Note that FAC-003-X shows changes to the
last approved version of the standard, while FAC-003-3 shows changes to the last version being
developed by the Project 2007-07 drafting team to incorporate Requirements for Generator Owners in
those standards.
PRC-004-2.1 is being posted for the first time with this posting, and is also being posted for a formal 45day comment period with an initial ballot. Because the changes are very limited, the Standards
Committee waived the initial formal comment period for this standard.
Instructions for Joining the Ballot Pool for Project 2010-07
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballots
at the following page: Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) One ballot pool list server has been set up and can be used for
communication on each of the standards being balloted for this project. The list server is: bp-201007_FAC-001-1_in@nerc.com
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy
of the comment form is posted on the project page.
Next Steps
Separate ballots will be conducted for each standard. These ballot windows will begin on Wednesday,
November 9, 2011 and end at 8 p.m. Eastern on Friday, November 18, 2011. NOTE: There is only one
ballot pool to join for this project. There will be four separate ballots, one for each standard, and
individuals who join this single ballot pool will be eligible to vote in all four ballots. This was done to
make the process simpler for those who are voting. If you have any questions, please contact Monica
Benson at monica.benson@nerc.net.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators so affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying FAC-001, FAC-003, and PRC-004 to Generator Owners as proposed in the redline
standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Document Title
2
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Document Title
3
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission
Interface
Four Ballot Windows Now Open Through 8 p.m. Eastern on Friday, November 18, 2011
Now Available
An initial ballot of each of the following standards is open through 8 p.m. Eastern on Friday, November
18, 2011. Note that the ballots are limited to the few modifications made to these standards to ensure
that there is a functional entity responsible for requirements associated with the transmission line
connecting the generator step up transformer to the transmission system (generator interconnection
Facility).
• FAC-001-1 – Facility Connection Requirements
•
Two versions of FAC-003 – Transmission Vegetation Management (FAC-003-3 and FAC003-X). Note that FAC-003-X shows changes to FAC-003-1, while FAC-003-3 shows changes
to FAC-003-2 developed by the Project 2007-07 drafting team. FAC-003-2 was adopted by
the NERC Board on November 3, and a revised version of FAC-003-3 showing the Project
2010-07 drafting team’s changes against the Board’s version has now been posted.
•
PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
IMPORTANT: Updates on Posted Standards
Last week, while the Project 2010-07 standards were posted for comment, NERC’s Board of Trustees
adopted FAC-003-2 – Transmission Vegetation Management (developed under Project 2007-07
Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with the applicable
regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both FAC-003-3
(proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERCapproved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to
carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the
SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity responsible for
managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Additionally, when the NERC Board of Trustees adopted FAC-003-2 –Transmission Vegetation
Management last week, it approved the standard with NERC staff-proposed VSLs rather than the
Project 2007-07 SDT-developed VSLs that were originally posted with both FAC-003-2 and FAC-003-3.
The posted versions of Project 2010-07’s FAC-003-3 now include the FAC-003-2 VSLs proposed by NERC
staff, since they are the set that was approved by the NERC Board of Trustees. Note that the Project
2010-07 SDT made no substantive changes to any version of the FAC-003-2 VSLs; the SDT simply
changed “Transmission Owner” to “responsible entity.” A text box has also been added to the VSL
section of FAC-003-3 for further clarity.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the
standards from the following page: https://standards.nerc.net/CurrentBallots.aspx
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, November 18, 2011. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page.
Special Instructions for Submitting Comments with a Ballot
Please note that comments submitted during the formal comment period and the ballots for the
standards all use the same electronic form, and it is NOT necessary for ballot pool members to submit
more than one set of comments. The drafting team requests that all stakeholders (ballot pool
members as well as other stakeholders) submit all comments through the electronic comment form.
Next Steps
The drafting team will consider all comments submitted during the formal comment period and ballots
to determine whether to make additional revisions to the standards.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
Standards Announcement – Project 2010-07
Generator Requirements at the Transmission Interface
2
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying FAC-001, FAC-003, and PRC-004 to Generator Owners as proposed in the redline
standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement – Project 2010-07
Generator Requirements at the Transmission Interface
3
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Ballot Pool Forming October 5 – November 4, 2011
Formal Comment Period October 5 – November 18, 2011
Initial Ballot Windows Open November 9 – 18, 2011
Available Now
The SDT has reviewed comments received during a 30-day formal comment period that took place
earlier this year, from June 17-July 17, 2011, and thanks to all those who provided feedback during that
comment period. The SDT has incorporated many of the suggested changes into its latest proposed
standards, as explained in the posted Consideration of Comments.
This is the second formal comment period and initial ballot period for three standards included in
Project 2010-07. Revised drafts of FAC-001-1 and two versions of FAC-003 – FAC-003-3 and FAC-003-X –
along with minor modifications to PRC-004-2.1, have been posted for a formal comment period and
initial ballot that will end on Friday, November 18, 2011. Note that FAC-003-X shows changes to the
last approved version of the standard, while FAC-003-3 shows changes to the last version being
developed by the Project 2007-07 drafting team to incorporate Requirements for Generator Owners in
those standards.
PRC-004-2.1 is being posted for the first time with this posting, and is also being posted for a formal 45day comment period with an initial ballot. Because the changes are very limited, the Standards
Committee waived the initial formal comment period for this standard.
Instructions for Joining the Ballot Pool for Project 2010-07
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballots
at the following page: Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) One ballot pool list server has been set up and can be used for
communication on each of the standards being balloted for this project. The list server is: bp-201007_FAC-001-1_in@nerc.com
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy
of the comment form is posted on the project page.
Next Steps
Separate ballots will be conducted for each standard. These ballot windows will begin on Wednesday,
November 9, 2011 and end at 8 p.m. Eastern on Friday, November 18, 2011. NOTE: There is only one
ballot pool to join for this project. There will be four separate ballots, one for each standard, and
individuals who join this single ballot pool will be eligible to vote in all four ballots. This was done to
make the process simpler for those who are voting. If you have any questions, please contact Monica
Benson at monica.benson@nerc.net.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators so affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying FAC-001, FAC-003, and PRC-004 to Generator Owners as proposed in the redline
standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Document Title
2
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Document Title
3
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Ballot Pool Forming October 5 – November 4, 2011
Formal Comment Period October 5 – November 18, 2011
Initial Ballot Windows Open November 9 – 18, 2011
Available Now
The SDT has reviewed comments received during a 30-day formal comment period that took place
earlier this year, from June 17-July 17, 2011, and thanks to all those who provided feedback during that
comment period. The SDT has incorporated many of the suggested changes into its latest proposed
standards, as explained in the posted Consideration of Comments.
This is the second formal comment period and initial ballot period for three standards included in
Project 2010-07. Revised drafts of FAC-001-1 and two versions of FAC-003 – FAC-003-3 and FAC-003-X –
along with minor modifications to PRC-004-2.1, have been posted for a formal comment period and
initial ballot that will end on Friday, November 18, 2011. Note that FAC-003-X shows changes to the
last approved version of the standard, while FAC-003-3 shows changes to the last version being
developed by the Project 2007-07 drafting team to incorporate Requirements for Generator Owners in
those standards.
PRC-004-2.1 is being posted for the first time with this posting, and is also being posted for a formal 45day comment period with an initial ballot. Because the changes are very limited, the Standards
Committee waived the initial formal comment period for this standard.
Instructions for Joining the Ballot Pool for Project 2010-07
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballots
at the following page: Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) One ballot pool list server has been set up and can be used for
communication on each of the standards being balloted for this project. The list server is: bp-201007_FAC-001-1_in@nerc.com
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy
of the comment form is posted on the project page.
Next Steps
Separate ballots will be conducted for each standard. These ballot windows will begin on Wednesday,
November 9, 2011 and end at 8 p.m. Eastern on Friday, November 18, 2011. NOTE: There is only one
ballot pool to join for this project. There will be four separate ballots, one for each standard, and
individuals who join this single ballot pool will be eligible to vote in all four ballots. This was done to
make the process simpler for those who are voting. If you have any questions, please contact Monica
Benson at monica.benson@nerc.net.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators so affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying FAC-001, FAC-003, and PRC-004 to Generator Owners as proposed in the redline
standards posted for comment.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Document Title
2
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Document Title
3
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission Interface
Initial Ballot Results
Now Available
Initial ballots for each of the following standards and their associated implementation plans closed on
November 18, 2011:
• FAC-001-1 – Facility Connection Requirements
•
Two versions of FAC-003 – Transmission Vegetation Management (FAC-003-3 and FAC-003X). Note that FAC-003-X shows changes to FAC-003-1, while FAC-003-3 shows changes to
FAC-003-2 developed by the Project 2007-07 drafting team. FAC-003-2 was adopted by the
NERC Board on November 3, and a revised version of FAC-003-3 showing the Project 2010-07
drafting team’s changes against the Board’s version was posted.
•
PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
Voting statistics for each ballot are listed in the table below, and the Ballot Results Web page provides
a link to the detailed results.
Standard
Quorum
Approval
FAC-001-1
88.22%
86.94%
FAC-003-3
85.08%
85.71%
FAC-003-X
84.82%
85.31%
PRC-004-2.1
84.29%
96.09%
Next Steps
The drafting team will consider all comments received and determine whether to make additional
changes to the standards. If the drafting team makes substantive changes to a standard, the standard
will be posted for a parallel 30-day comment period and successive ballot. If the drafting team decides
that no substantive changes are needed to a standard, a recirculation ballot will be conducted.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. This can be accomplished by
properly applying FAC-001, FAC-003, and PRC-004 to Generator Owners as proposed in the redline
standards posted for comment. Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement Project 2010-07
Generator Requirements at the Transmission Interface
2
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010-07_FAC-001-1 Initial Ballot_in
Password
Ballot Period: 11/9/2011 - 11/18/2011
Log in
Ballot Type: Initial
Total # Votes: 337
Register
Total Ballot Pool: 382
Quorum: 88.22 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
86.94 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.3
0.8
7.1
#
Votes
Fraction
65
5
47
20
64
34
0
5
1
7
248
Negative
Fraction
0.915
0.5
0.81
0.909
0.889
0.85
0
0.5
0.1
0.7
6.173
Abstain
No
# Votes Vote
6
0
11
2
8
6
0
0
2
1
36
0.085
0
0.19
0.091
0.111
0.15
0
0
0.2
0.1
0.927
12
2
13
6
10
8
0
0
1
1
53
12
2
9
3
12
3
1
2
1
0
45
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
Affirmative
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
View
View
View
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
View
Negative
View
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Negative
View
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
View
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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https://standards.nerc.net/BallotResults.aspx?BallotGUID=ca4205a5-90bd-487a-b1ee-079ae6a22f71[11/21/2011 9:08:08 AM]
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-X_in
Password
Ballot Period: 11/9/2011 - 11/18/2011
Log in
Ballot Type: Initial
Total # Votes: 324
Register
Total Ballot Pool: 382
Quorum: 84.82 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.31 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.2
0.7
6.8
#
Votes
Fraction
57
4
42
15
56
30
0
4
2
5
215
Negative
Fraction
0.891
0.4
0.792
0.882
0.903
0.833
0
0.4
0.2
0.5
5.801
Abstain
No
# Votes Vote
7
1
11
2
6
6
0
0
0
2
35
0.109
0.1
0.208
0.118
0.097
0.167
0
0
0
0.2
0.999
16
2
17
8
16
11
0
1
1
2
74
15
2
10
6
16
4
1
2
2
0
58
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
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Affirmative
Affirmative
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Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
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Affirmative
Affirmative
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Affirmative
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Affirmative
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Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
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NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
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Affirmative
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Affirmative
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NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
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Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Abstain
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
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NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1eae9053-8d4d-4755-ab1e-34283de6fc44[11/21/2011 9:09:36 AM]
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Affirmative
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Affirmative
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Affirmative
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NERC Standards
6
6
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6
6
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6
6
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8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
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Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-3 Initial Ballot_in
Password
Ballot Period: 11/9/2011 - 11/18/2011
Log in
Ballot Type: Initial
Total # Votes: 325
Register
Total Ballot Pool: 382
Quorum: 85.08 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.71 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.2
0.8
6.9
#
Votes
Fraction
58
5
44
16
58
31
0
4
2
5
223
Negative
Fraction
0.866
0.5
0.815
0.889
0.906
0.838
0
0.4
0.2
0.5
5.914
Abstain
No
# Votes Vote
9
0
10
2
6
6
0
0
0
3
36
0.134
0
0.185
0.111
0.094
0.162
0
0
0
0.3
0.986
14
2
16
7
14
10
0
1
1
1
66
14
2
10
6
16
4
1
2
2
0
57
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
Ballot
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
Affirmative
View
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Negative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
Abstain
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=93bf411a-730e-486f-bcf6-b7ae74014458[11/21/2011 9:08:45 AM]
View
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
View
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
View
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
View
View
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
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Ballot Results
Ballot Name: Project 2010-07 PRC-004-2.1 Initial Ballot_in
Password
Ballot Period: 11/9/2011 - 11/18/2011
Log in
Ballot Type: Initial
Total # Votes: 322
Register
Total Ballot Pool: 382
Quorum: 84.29 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
96.09 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
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Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.2
0.8
7
#
Votes
Fraction
61
5
52
20
63
35
0
5
2
8
251
Negative
Fraction
0.953
0.5
0.945
0.952
0.955
0.921
0
0.5
0.2
0.8
6.726
Abstain
No
# Votes Vote
3
0
3
1
3
3
0
0
0
0
13
0.047
0
0.055
0.048
0.045
0.079
0
0
0
0
0.274
15
2
14
5
11
9
0
0
1
1
58
16
2
11
5
17
4
1
2
2
0
60
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ef1ad9f1-31b0-4769-bb6e-8e064361e03d[11/21/2011 9:10:18 AM]
Ballot
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Abstain
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ef1ad9f1-31b0-4769-bb6e-8e064361e03d[11/21/2011 9:10:18 AM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ef1ad9f1-31b0-4769-bb6e-8e064361e03d[11/21/2011 9:10:18 AM]
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ef1ad9f1-31b0-4769-bb6e-8e064361e03d[11/21/2011 9:10:18 AM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ef1ad9f1-31b0-4769-bb6e-8e064361e03d[11/21/2011 9:10:18 AM]
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
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NERC Standards
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Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
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Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
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John J. Ciza
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Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
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Peter H Kinney
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David F. Lemmons
Frank R. McElvain
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
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Diane J Barney
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Klaus Lambeck
Linda Campbell
James D Burley
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Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
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Individual or group. (40 Responses)
Name (24 Responses)
Organization (24 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
Question 1 (34 Responses)
Question 1 Comments (40 Responses)
Question 2 (32 Responses)
Question 2 Comments (40 Responses)
Question 3 (33 Responses)
Question 3 Comments (40 Responses)
Question 4 (33 Responses)
Question 4 Comments (40 Responses)
Question 5 (32 Responses)
Question 5 Comments (40 Responses)
Question 6 (30 Responses)
Question 6 Comments (40 Responses)
Question 7 (30 Responses)
Question 7 Comments (40 Responses)
Question 8 (28 Responses)
Question 8 Comments (40 Responses)
Question 9 (4 Responses)
Question 9 Comments (40 Responses)
Question 10 (0 Responses)
Question 10 Comments (40 Responses)
Individual
Chris Higgins/Stephen Enyeart/Chuck Mathews/Charles Sheppard
Bonneville Power Administration
BPA thanks you for the opportunity to comment on Project 2010-07, Generator Requirements at the
Transmission Interface. BPA stands in support of the proposed revisions and has no comments or
concerns at this time.
Individual
Thad Ness
American Electric Power
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
SERC OC Standards Review Group
Gerald Beckerle
Yes
Please verify within the applicability section (4.2.1) you intended to use the word “within” rather than
some other wording.
Yes
Yes
Yes
Yes
Yes
Please list the set of standards are you referencing.
See comments on Question 7. If the standards referenced in question 7 are FAC-001, FAC-003 and
PRC-004, we would answer yes to this question.
See comments on Questions 7 & 8.
The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”
Individual
Carla Bayer
BP Wind Energy North America Inc.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
Electric Power Supply Association
Jack Cashin
Yes
All TO requirements for FAC-001-1 would apply if and when GO executes an Agreement to evaluate
the reliability impact of interconnecting a third party Facility to its existing generation interconnection
Facility. The execution of the agreement is necessary to comply with FAC-002-1 and start the
compliance clock with the applicable regulatory authority. Thus as the Project 2010-07 Standard
Drafting Team (SDT) in its technical justification has stated, “If, and only if, the existing owner of a
generator interconnection Facility has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to its existing generation Facility” then FAC-001-1 should apply.
EPSA concurs with SDT’s conclusion. The SDT has examined the issue regarding if future requests for
transmission service on the interconnection Facility and in doing so acknowledged that when that
Facility adopted open access and was providing transmission service it would necessitate reevaluation of the need for the Facility to be maintained in accordance with FAC-001-1, Requirements
2 and 4. This service would indeed prompt the necessary agreement the SDT contemplates in its
technical justification of FAC-001-1. EPSA believes this serves as the necessary trigger for evaluation
of Requirements 2 and 4 under FAC-001-1 for GOs.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
Southwest Power Pool Standards Development Team
Jonathan Hayes
No
Based on the applicability section of FAC-001 we feel that the strike through should have been kept.
It limited the requirement to just those generator owners who had agreements in place, which we feel
is appropriate.
Yes
No
There is a possibility of some conflict with the Bulk Electric System Definition. This should be
consistent with the Transmission Owner requirements if the lead is determined part of the BES.
No
The effective dates should be consistent with the original standard. If there is a reason for the
extension we would like to know why.
Yes
Yes
Yes
No
We agree that the standards being addressed are correct. See above comments. There are some
issues with the determination of which facilities are deemed BES since ownership of what may be a
BES facility may not always be by a Transmission Owner. All relevant standards should apply to BES
facilities regardless of ownership.
Individual
John Bee on behalf of Exelon
Exelon
Yes
Yes
No
FAC-003 - Exelon supports the one mile length qualifier, but feels that additional clarification is
needed to determine the points of demarcation. There are too many differing physical configurations
to use a “fence line” as a determination of applicability. Suggest that the tie line length be defined as
“from the Generator Step up Transformer GSU to the point of interconnection between the GO and TO
owned equipment.” Also suggest that the standard define what constitutes a generation station
switchyard.
Yes
Yes
Yes
Yes
Yes
PRC-004 - suggest that the Standard state that responsibility for the analysis of missoperations of
protective equipment shall be the responsibility of the owner of the protective equipment.
Individual
Dennis Sismaet
Seattle City Light
Yes
Key points are that (1) an executed agreement is required before evaluations of impacts are
necessary and (2) this only applies when a third party is connecting to the generating interconnection
line.
Yes
The proposed changes for FAC-001-1 state a 45 day period to complete the evaluation. Not sure what
the question is referring to regarding “ 1 year “?
Yes
Key points are the greater than one mile with clear statement of “…beyond the fenced area of the
generating switchyard.”
Yes
The explanation deals with the fact that there are simultaneous revisions of FAC-003 underway by
two different teams.
Yes
Yes
Yes
Yes
Individual
Michelle D'Antuono
Ingleside Cogeneration LP (Occidental Chemical)
No
Unfortunately, the vital point of this requirement revolves around whether or not a Generator Owner
is compelled externally to allow access to their interconnection facilities. If the GO is driving the
connection for financial or other business reasons, there is no reason they should not be responsible
for developing AND maintaining a facility connection requirements document. Otherwise, when the
local transmission system requirements change for any reason, there will be no entity responsible to
ensure that the third party will conform as well. Conversely, if the GO should be compelled to allow
access to a third party, it is the responsibility of the “compeller” to handle all the related reliability
studies and documents. This may include the development of a CFR which separates reliability tasks
between the GO and other entities – especially if a TSP registration is required. This ensures that the
Regional Entity, PUC, RTO, or other regulator must budget dollars and resources directly related to
their action – not cause them to be directed to a GO.
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the drafting team
needs to specify how the requirements apply to an in-place “executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility
that is used to interconnect to the Transmission System.” In the view of Ingleside Cogeneration LP, if
the Agreement takes effect even one day before FAC-001-1 does, requirements R2 and R3 do not
apply. Without this clarification, it is possible that NERC’s Compliance team will apply the
requirements retroactively – with minimum industry input.
No
Ingleside Cogeneration LP is very concerned that the attempt to develop “bright-line” criteria to
assign applicability to either version of FAC-003 is misplaced. As seen with NERC’s recent proposed
directive related to Generator-Transmission interconnections, those thresholds can be arbitrarily
reduced based upon regulators aversion to risk – not scientific evidence. (As it stands today, NERC
has proposed any interconnection facility operating at 100 kV or higher and greater than 3 spans in
length be applicable – which is even stricter than the TO thresholds in FAC-003.) This would suggest
that a reliability assessment consistent with the TPL standards must be the determining factor. If the
Planning Coordinator or Transmission Planner can show that the Generator-Transmission
interconnection could contribute to a violation of an SOL or IROL, then a vegetation management
program may be in order. Furthermore, there needs to be some level of common sense applied if a
GO-TO interconnection is located in an area where vegetation clearance is never an issue. A one-sizefits-all requirement based upon vegetation growth in the sub-tropics, should not automatically apply
in the desert. In our view, every dollar spent to control vegetation in an arid climate is one less dollar
available to purchase advanced telemetry, AGC systems, and other items which have a far greater
impact on reliability.
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the drafting team
needs to specify when the first vegetation management inspection quarterly report, and any other
requirement with an assigned interval in FAC-003-3 or FAC-003-X. Even if the decision is to adopt the
same criteria proposed in CAN-0012, the industry is better served with a clear distinction made up
front.
Yes
Ingleside Cogeneration agrees that the SDT’s approach is thorough. We are far more concerned about
FAC-003’s applicability criteria and implementation time frame at this point – as stated in our
responses to questions 3 and 4.
Yes
Ingleside Cogeneration LP believes the SDT has spent a significant amount of time and effort to
demonstrate that only FAC-001, FAC-003, and PRC-004 need to be modified to address any reliability
gaps that may exist related to the GO-TO interconnection. We agree that the other
standards/requirements identified by the Ad Hoc Group are covered elsewhere.
Yes
Although the SDT is nearing conclusion on the closing of reliability gaps, the unnecessary registration
of GOs and GOPs as TOs and TOPs is far from resolved in our view. Ingleside Cogeneration’s concern
is based upon NERC’s recent proposal to dictate an interim GO-TO interconnection solution which
completely bypasses the Standards Development Process. Frankly, it seriously brings to question the
nature of the consensus-driven process – which appears to be moving in a dictatorial direction.
No
See comments to questions 1 through 4.
Ingleside Cogeneration LP believes that the set of standards proposed by the SDT is technologically
accurate and defensible. The open issue is if the ERO and FERC expect more standards to be included
– whether based upon sound reliability principals or not.
Group
Northeast Power Coordinating Council
Northeast Power Coordinating Council
Guy Zito
Guy Zito
No
The intent of the draft language in FAC-001-1 is to provide guidance for addressing the alleged
reliability gap that exists between GO/GOPs that own/ operate transmission facilities but are not
registered as TO/TOPs. The impact of the revised language will depend on the characterization of the
generator lead after the “third party “ connects to the existing generator lead. IF the generator lead is
owned by the TO utility after the third party connection : The proposed DRAFT FAC-001 language
suggests that within 45 days of a 3rd party having an executed Agreement to evaluate the reliability
impact of interconnecting, the existing generator needs to document and publish facility connection
requirements. The proposed language suggests that a third party can commandeer existing
generators leads and interconnect. A reclassification would be required because “third party” power
would flow through the downstream portions of the existing leads. This introduces significant
challenges for defining ownership / transfer of installed assets as well as real property, easements,
operational jurisdiction, O&M cost responsibility, etc. The FERC approved pro-forma Attachment X
Interconnection Agreement clearly states that the project Developer must meet all Applicable
Reliability Standards which means that all requirements and guidelines of the Applicable Reliability
Councils, and the Transmission District to which the Developer’s Large Generating Facility is directly
interconnected. As an example, to accommodate this NERC proposal, the FERC approved NYISO pro-
forma tariff would need to be revised to allow this “third party” use. The pro-forma interconnection
tariff also states that the Developer must provide updated project information prior to the Facilities
Study. The Facilities Study might not be made until several years after the Interconnection Request
/Feasibility Study is made (“executed Agreement to evaluate the reliability impact of interconnecting”
in this proposed draft is akin to the Interconnection Request/Feasibility Study). Placing the
requirement to have the existing Generator Owner publish reliability requirements for a potential
“third party user”, without the generator having any knowledge of the potential reliability outcomes or
asset transfer / ownership issues is not a reasonable expectation. The interconnection of a third party
to an existing generator lead would force existing generators to revise their Interconnection
Agreements with FERC. The “third party”, would at a minimum, need to comply with the existing
Generators reliability obligations as specified in the Interconnection Agreement. IF the third party
connects to the GO owned generator lead, the GO will be considered a TO: A TO would not be
involved, other than review of the SRIS and Facilities reports. The difficult thing for an existing GO
would be to prepare, within 45 days of having an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility, a document
listing the requirements. To allow for the above possibilities, the language for applicability of FAC-001
to GO’s or GOP’s, should be : “Each applicable Generator Owner shall, at least 60 days prior to
execution of a Facilities / Class Year Study Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System, document and publish its Facility connection requirements
to ensure compliance with NERC Reliability Standards and applicable Regional Entity, sub regional,
Power Pool, and individual Transmission Owner planning criteria and Facility connection
requirements.”
Yes
No
Suggest in FAC-003-X; 4.3.1. that Regional Entity be changed to RE as listed in 4.2.1 for consistency.
Also Regional Entity is used throughout the rest of the document, suggest using RE for consistency. In
FAC-003-3; 4.3.1. add station to the following: “ Overhead transmission lines that extend greater
than one mile or 1.609 kilometers beyond the fenced area of the generation station switchyard and
are” to show consistency as it is written in FAC-003-X 4.3.1. The technical justification characterized
the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard) as “approximate line of sight [sic] from a fixed point” and noted that this line of sight
may be limited by local terrain. Where line of sight of the radial corridor is limited on a clear day due
to terrain, the one mile exemption must be limited in distance to no more than the line of sight on a
clear day beyond the fenced area.
Yes
Yes
Yes
Yes
Yes
No additional comments.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
Southwest Power Pool Regional Entity
Emily Pennel
Yes
No
No action is required unless a GO has an executed third-party agreement. If a GO has an agreement,
the standard already includes a 45-day timeframe for the GO to document and publish its facility
connection requirements.
Yes
Yes
Yes
No
The Technical Justification document did not review the standards FERC identified in paragraphs 71
and 87 of 135 FERC ¶ 61,241 ORDER DENYING APPEALS OF ELECTRIC RELIABILITY ORGANIZATION
REGISTRATION DETERMINATIONS. The SDT needs to review these standards to determine if changes
are needed; otherwise, FERC will require registration of GOs and GOPs as TOs and TOPs to address
reliability gaps. If the SDT determines no changes are needed to these FERC-identified standards,
they should provide justification.
The SDT should consider the standards that FERC identified in 135 FERC ¶ 61,241.
Individual
Greg Rowland
Duke Energy
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Kirit Shah
Ameren
Yes
Yes
No
(a) There is no technical basis for the one mile length exemption. In fact, one could argue that a very
short line, 300 feet in length, that experienced a fault from a tree at "the end of the circuit", i.e near
the switchyard fence, would have much more of an impact on the BES because the fault would be
limited by much less impedance. (b) It is unclear in this version if a GO that owned one line that was
1.2 miles in length, and fifty other lines that did not exceed 500' in length would have to comply for
all fifty-one lines or not. It would appear that they would as they owned at least one more than a
mile. This ambiguity should be removed.
No
The 2 year compliance time line is far too long. There is significant industry evidence that was
developed in the drafting of Version 2 that supports a one year compliance time-line for new lines.
This is evidenced in Version 2. Thus there is no basis for the 2 years.
(a) There is no technical basis for the one mile length exemption. In fact, one could argue that a very
short line, 300 feet in length, that experienced a fault from a tree at "the end of the circuit", i.e near
the switchyard fence, would have much more of an impact on the BES because the fault would be
limited by much less impedance. (b) It is also unclear in this version if a GO that owned one line that
was 1.2 miles in length would have to comply for the entire length of said line, or just 0.2 miles of
said line. If the GO is responsible for 1.2 miles, then that argues that the first mile is important and
consequently there is no basis for ignoring the first mile on other lines. If the GO is only responsible
for 0.2 miles, what is the technical basis to ignore a mile? And would it be the first mile from the
switchyard that is ignored, or is the middle mile, or the last mile where it connects to the TO? Or
could the GO decide? Or could the GO pick sections of the line that amount to a mile that they can
ignore? This seems like something that should be addressed for compliance. (c) The 2 year
compliance time line is far too long. There is significant industry evidence that was developed in the
drafting of Version 2 that supports a one year compliance time-line for new lines. This is evidenced in
Version 2. Thus there is no basis for the 2 years
Yes
No
Please refre to our comments in reposnes to #3, #4, and #5 above.
Individual
John Seelke
PSEG
No
We revised this partial sentence to the following: “Each applicable Generator Owner shall, within 45
days of having an executed Agreement to evaluate the reliability impact of interconnecting a third
party Facility to the Generator Owner’s existing Transmission Facility that is used for connection to
the interconnected Transmission systems (under FAC-002-1), ...” - The phrase “Generator Owner’s
existing Facility that is used to interconnect to the Transmission System” was changed to “Generator
Owner’s existing Transmission Facility that is used for connection to the interconnected Transmission
systems.” - “Transmission” was added before Facility to exclude connections elsewhere;
“Transmission System” was changed to “Transmission systems” because while “Transmission” and
“System” are defined in the NERC Glossary, “System” means “A combination of generation,
transmission, and distribution components.” “Transmission systems” do not have generation or
distribution components, so a lower case “system” is warranted. - In addition, the suggested phrase
“interconnected Transmission systems” (plural "systems") uses identical language from FAC-002-1,
except that we capitalized “Transmission.
Yes
No
No
It’s no longer applicable.
Yes
No
PRC-005-1 - Transmission and Generation Protection System Maintenance and Testing was
recommended by the Ad Hoc Group for modification, but not addressed to the technical justification
document. It should be.
No
It would be helpful if the SDT defined what it means by the term “radial generator interconnection
Facilities.” Does it mean interconnection Facilities that under Normal Clearing for a fault do not
interrupt flows on other BES Elements? This is also confusing because of the radial exclusion included
in the BES definition work in Project 2010-17. That definition would allow part of a three-terminal
circuit to be excluded from the BES, while the other parts are included in the BES.
No
Yes
We believe that the Ad Hoc Group’s suggestions regarding PRC-005-1 - Transmission and Generation
Protection System Maintenance were correct and that this standard should have been modified by the
SDT in a manner similar to the way the SDT modified PRC-004-2. This would require modifying R1
and R2 in PRC-005-1a (the current version) to include protection systems in the generator
interconnection Facility. In addition, the SDT should evaluate modifying PER-002-0 – Operation
Personnel Training. In doing so the SDT completes one of the open FERC directives in Order 693.
Paragraph 1363 addresses GOP training: 1363. Further, the Commission agrees with MidAmerican,
SDG&E and others that the experience and knowledge required by transmission operators about BulkPower System operations goes well beyond what is needed by generation operators; therefore,
training for generator operators need not be as extensive as that required for transmission operators.
Accordingly, the training requirements developed by the ERO should be tailored in their scope,
content and duration so as to be appropriate to generation operations personnel and the objective of
promoting system reliability. Thus, in addition to modifying the Reliability Standard to identify
generator operators as applicable entities, we direct the ERO to develop specific Requirements
addressing the scope, content and duration appropriate for generator operator personnel.
Group
MRO NSRF
Will SMith
Yes
Yes
No
The NSRF agrees with the drafting committees desire to eliminate arbitrary and capricious behavior of
auditors and industry staff by precisely defining the point at which measurement starts for the length
of transmission line. The concern the NSRF has with the proposed wording is that many generating
station may not have a “generating station switchyard” as implied by the proposed wording. Often the
generator leads (e.g. 20 kV) will exit the generator and connect to transformers located in
transformer bays directly adjacent to the plant. From the transformers the now greater than 200 kV
lines will be routed to the point of interconnect or a generating unit switchyard, possibly miles or
yards away. By no one’s definitions would the transformer bays adjacent to the plant be considered a
switchyard. The plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences, security patrols, or
other barriers yards or miles from the transformer but enveloping the switchyard. The valid
assumption made by the drafting team is that transmission lines within an area tightly controlled by
the generator operator poses very little risk to the BES as a result of vegetation contact. This
assumption is based on the valid observation that these areas are routinely occupied and observed by
station personnel and as a result unexpected and unacceptable vegetation growth is highly unlikely
because it is controlled by routine maintenance. It also correctly assumes that some distance past the
controlled area is acceptable since this area would also be under near continuous observation. The
problem comes in defining both a tightly controlled area and a line of site. We suggest the following:
Controlled Area: A perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is routinely
occupied such that unexpected and unacceptable vegetation growth would be observed and correct as
a matter of routine maintenance. Line of Sight: NSRF recommends a two kilometer distance from the
controlled area perimeter. Our assessment is that an individual of average height would have a line of
site of approximately 4 Kilometers. Therefore, we recommended a distance of 2 kilometers from the
Controlled Area of the plant to provide margin. The revised applicability statement would read as
follows: “Generator Owner that owns an overhead transmission line(s) that extends greater than 2.0
kilometers beyond the Controlled Area of the generating station up to the point of interconnection
with a Transmission Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in the region.
Furthermore we applaud the committee for using the metric system to identify the acceptable
distance for this standard and urge it to remove all references to English units. We strongly suggest
this drafting team and all future drafting team abandon the anachronistic English measurement
system. This archaic system, based on the length of an average barley corn, should be abandon in all
scientific and engineering endeavors.
Yes
There may be a typographical error on the effective date. As currently drafted the standard states: In
those jurisdictions where regulatory approval is required, Requirement R1 applied to the Generator
Owner becomes effective on the first calendar day of the first calendar quarter one year after the date
of the order approving the standard from applicable regulatory authorities where such explicit
approval for all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 becomes effective on the first day of the first calendar quarter one year
following Board of Trustees adoption. Should it be worded as follows? In those jurisdictions where
regulatory approval is required, Requirement R1 applied to the Generator Owner becomes effective on
the first calendar day of the first calendar quarter one year after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all requirements is
required. In those jurisdictions where no regulatory approval is required, Requirement R3 R1 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees adoption.
Yes
No
The NSRF has one concern with the current justification and definitions. At some point, if enough
interconnections are made to generator outlet leads in accordance with FAC-001, the original
generator operator will be a Transmission Operator and a Transmission Owner. This point in time
needs to be explicitly defined by the drafting team.
Yes
Yes
The NSRF agrees if the drafting team incorporates as suggested improvements
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
No
There should be no qualifying exemption to FAC-003 for Generator Owners.
Yes
Yes
Yes
No
The modifications are appropriate with the exception noted in question #3.
Group
American Wind Energy Association
Natalie McIntire
Yes
AWEA appreciates that this standard specifies that it has limited applicability. For instance, only those
generators that have an executed agreement with a third party wishing to interconnect must
document and publish Facility connection requirements. We believe the proposed 45-day time window
is a minimum for GO/GOP owners of generator lead lines to provide this documentation following
execution of such an agreement. Anything less than 45 days could result in a burdensome and hard
to meet deadline for GO/GOP staff. However, AWEA believes that extending this time window for
publishing Facility connection requirements to 90 days after an executed agreement would be
beneficial. We believe this will allow the GO/GOP owners of generator leads more time to coordinate
with their interconnecting Transmission Providers and will result in more reliable and coordinated
connection requirements for the generator lead.
Yes
Yes, since there is no exigent reason why this standard needs to be put in place at once, we support
the one-year compliance timeframe. We believe that it will allow generators a reasonable time to
comply with the requirement.
Yes
Applying the vegetation management requirements to only generator lead lines that extend more
than “one mile beyond the fenced area of the generating station switchyard” strikes a reasonable
balance among the many stakeholder positions expressed on this topic. We think that as this criterion
recognizes that there is little need for a vegetation management plan for shorter lines. It should
explicitly state that this is true for all such facilities with lines of that length or smaller.
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this standard needs to
be put in place at once, we support the proposed compliance timeframe. We believe that it will allow
generators a reasonable time to comply with the requirement.
Yes
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is no need for
additional standards to be applied to GO/GOP lead lines as they will not improve the reliability of the
Bulk Electric System. In fact, as noted above, such additional standards may decrease reliability by
diverting the GO/GOP’s resources from the operation of the equipment that actually produces
electricity – the generation equipment itself.
Yes
AWEA believes that the standards modifications proposed by the SDT should address any genuine
reliability gap with regard to generator lead lines, rather than just perceived but unsupported threats.
To that end, we support the approach that the SDT appears to be taking of modifying a limited
number of applicable standards so that they apply to GO/GOP lead lines. In particular, we fully
support the fact that the SDT recognizes that GO/GOPs should not automatically be required to
register as TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Yes
For the most part, AWEA agrees that the SDT proposal strikes a reasonable balance and provides the
requisite level of clarity and certainty necessary for GO/GOPs to understand their responsibilities and
compliance requirements.
AWEA appreciates the opportunity to submit these comments on the NERC Project 2010-07. AWEA
supports the general direction indicated by both the Generator Requirements at the Transmission
Interface Ad Hoc Group and the Project 2010-07 Standards Development Team. We agree with the
sentiments from both groups that a GO or GOP that also owns or operates a generator lead line
should not be required to register as a TO or TOP strictly because they own or operate a generator
lead line. We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards would
have little effect on or benefits to reliability of the Bulk Electric System, and could even detract from
it. AWEA supports the intent and goal of the SDT to ensure that all generator-owned Facilities are
appropriately covered under NERC’s Reliability Standards. We also agree with the SDT that while
many GO/GOPs operate Elements and Facilities that might be considered by some entities to be
Transmission, these are most often radial Facilities that are not part of the integrated grid, and as
such should not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore, we support the
SDT’s approach of identifying a very limited number of TO/TOP standards, such as FAC-001 and FAC003, which should also apply to GO/GOP owners of generator lead lines. We would be concerned,
however, if additional requirements were added beyond FAC-001, FAC-003, and PRC-004.
Consideration of any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the impact on the
reliability of the Bulk Electric System.
Group
SERC Planning Standards Subcommittee
Charles W. Long
Yes
Yes
No
We believe there should be no exemption for Generator Owners.
Yes
Yes
Yes
Yes
No
See our comments above for question # 3.
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers”
Group
Puget Sound Energy, Inc.
Tom Flynn
The changes to this standard are minor, and seem to be centered around including "generator
Interconnection facilities" to R2. This added phrase and the statement in 1.4 Data Retention
"Generator Owner that owns a generation Protection System" seems to assume that the generator
owner and generator interconnection facilities owner is always the same. This is not always the case,
and will make this standard language confusing to prepare evidence for. A suggestion would be to
revise the language to allow for a separate generator owner and generator interconnection facilities
owner.
Individual
Ravi Bantu
RES Americas Development
Yes
RES Americas and AWEA appreciate that this standard specifies that it has limited applicability. For
instance, only those generators that have an executed agreement with a third party wishing to
interconnect must document and publish Facility connection requirements. We believe the proposed
45-day time window is a minimum for GO/GOP owners of generator lead lines to provide this
documentation following execution of such an agreement. Anything less than 45 days could result in a
burdensome and hard to meet deadline for GO/GOP staff. However, we believes that extending this
time window for publishing Facility connection requirements to 90 days after an executed agreement
would be beneficial. We believe this will allow the GO/GOP owners of generator leads more time to
coordinate with their interconnecting Transmission Providers and will result in more reliable and
coordinated connection requirements for the generator lead.
Yes
Yes, since there is no exigent reason why this standard needs to be put in place at once, we support
the one-year compliance timeframe. We believe that it will allow generators a reasonable time to
comply with the requirement.
Yes
Applying the vegetation management requirements to only generator lead lines that extend more
than “one mile beyond the fenced area of the generating station switchyard” strikes a reasonable
balance among the many stakeholder positions expressed on this topic. We think that as this criterion
recognizes that there is little need for a vegetation management plan for shorter lines, it should
explicitly state that this is true for all such facilities with lines of that length or smaller.
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this standard needs to
be put in place at once, we support the proposed compliance timeframe. We believe that it will allow
generators a reasonable time to comply with the requirement.
Yes
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is no need for
additional standards to be applied to GO/GOP lead lines as they will not improve the reliability of the
Bulk Electric System. In fact, as noted above, such additional standards may decrease reliability by
diverting the GO/GOP’s resources from the operation of the equipment that actually produces
electricity – the generation equipment itself.
Yes
We believe that the standards modifications proposed by the SDT should address any genuine
reliability gap with regard to generator lead lines, rather than just perceived but unsupported threats.
To that end, we support the approach that the SDT appears to be taking of modifying a limited
number of applicable standards so that they apply to GO/GOP lead lines. In particular, we fully
support the fact that the SDT recognizes that GO/GOPs should not automatically be required to
register as TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Yes
For the most, we agree that the SDT proposal strikes a reasonable balance and provides the requisite
level of clarity and certainty necessary for GO/GOPs to understand their responsibilities and
compliance requirements.
RES and AWEA appreciates the opportunity to submit these comments on the NERC Project 2010-07.
We support the general direction indicated by both the Generator Requirements at the Transmission
Interface Ad Hoc Group and the Project 2010-07 Standards Development Team. We agree with the
sentiments from both groups that a GO or GOP that also owns or operates a generator lead line
should not be required to register as a TO or TOP strictly because they own or operate a generator
lead line. We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards would
have little effect on or benefits to reliability of the Bulk Electric System, and could even detract from
it. RES and AWEA supports the intent and goal of the SDT to ensure that all generator-owned
Facilities are appropriately covered under NERC’s Reliability Standards. We also agree with the SDT
that while many GO/GOPs operate Elements and Facilities that might be considered by some entities
to be Transmission, these are most often radial Facilities that are not part of the integrated grid, and
as such should not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore, we support the
SDT’s approach of identifying a very limited number of TO/TOP standards, such as FAC-001 and FAC003, which should also apply to GO/GOP owners of generator lead lines. We would be concerned,
however, if additional requirements were added beyond FAC-001, FAC-003, and PRC-004.
Consideration of any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the impact on the
reliability of the Bulk Electric System.
Individual
Katy Wilson
Sempra Generation
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Sempra Generation also supports the comments, being concurrently filed, of the Electric Power
Supply Association (EPSA).
Individual
Joe Petaski
Manitoba Hydro
No
Manitoba Hydro has the following comments: 1) The intention of the NERC SDT in revising these
standards is not clear. While the Technical Justification document states that the SDT intended to
focus on a Generator Owner’s radial interconnection facilities, the scope of the revised standard (s) is
not confined to such facilities. The very broadly defined term “Facility” is used. Moreover, the
Technical Justification document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not specifically address the issue
of radial facilities and supported NERC’s registration of GOs as TOs. 2) If the drafting team intends to
limit the scope of FAC-001-1 to GO owned radial generator interconnection facilities that are not
deemed BES transmission and therefore would not require the registration of the GO as a TO,
Manitoba Hydro disagrees with the proposed changes to FAC-001-1 as Generator Owners may not
have the models or expertise to perform interconnection studies to determine if there is an impact on
the Transmission Network. This concern is echoed in the technical justification document provided by
NERC: ‘the SDT acknowledges that the Generator Owner may not, at the time it agrees or is
compelled to allow a third part to interconnect, have the necessary expertise to conduct the required
interconnect studies to meet this standard… the Generator Owner will have to acquire such expertise.
How the Generator Owner chooses to do so is not for the SDT to determine.’ Although it may not be
for the SDT to determine how a GO obtains technical expertise, ensuring that such expertise is
acquired before a GO conducts the required interconnection studies should be a concern to NERC as
this directly affects the reliability of the BES. As a result, all interconnection requests should be
implemented by the TO providing the GO with connection to the BES regardless if the interconnection
point is within a Generation Owner facility or End-User facility as the TO is in the best position to set
unbiased connection requirements to ensure the reliability of the BES is maintained. If the scope of
FAC-001-1 also applies to GO owned BES transmission facilities, Manitoba Hydro strongly believes
that the Compliance Registry should apply and the GOs should be required to register as a TO and
abide by all applicable standards to that functional type. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions. Reliability gaps would
be better addressed if select GOs and GOPs registered as TOs and TOPs to ensure all reliability
standards, including the protection standards, are met so the reliability of the BES is maintained. At
this time, this would not lead to a large number of extra registrations since, as stated in the technical
justification document, ‘interconnection requests for Generator Owner Facilities are still relatively
rare. 3) If the redline changes are implemented, GOs are removed from R4, thereby removing the
obligation for GOs to maintain their connection requirements. If GOs are included in FAC-001, they
should be held accountable to the same level as TOs and should be required to maintain their
connection requirements. Requiring a GO to maintain connection requirements would be especially
beneficial to the GO themselves. In the majority of instances, any GO that is an Applicable Entity for
FAC-001 would initially be inexperienced in performing interconnection studies and would benefit from
regular and frequent review of their connection requirements as experience and expertise are gained.
4) The revision to FAC-001-1 R2 may be problematic, depending on what was intended. Under the
revised requirement, the obligation to comply is dependent on the execution of an agreement to
evaluate reliability impacts under FAC-002-1. However, FAC-002-1 does not clearly require the
execution of an agreement by the Generator Owner. FAC-002-1 only requires the Generator Owner to
“coordinate and cooperate on its assessments with its Transmission Planner and Planning Authority”.
Accordingly if a Generator Owner coordinates without executing an agreement to perform an
assessment, compliance with FAC-001 R1 will not be required. 5) Manitoba Hydro would also like to
point out that if the redline changes are implemented, it will greatly increase the complexity of
coordination required under FAC-002-1 for Transmission Planners/Planning Authorities.
No
See question 1 comments.
No
Manitoba Hydro does not support the changes being proposed in this project. If a Generator Owner is
required to register as a TO, all the Requirements applicable to a TO should apply. There is no need to
change specific Reliability Standards to allow the Generator Owner to perform only selected TO
functions.
No
See question 3 comments.
No
See question 3 comments.
No
See Question 7 comments.
No
The SDT’s proposed modifications gives special treatment to the Generator Owner in that it allows the
Generator Owner TO status for a couple of standards (FAC-001, FAC-003 and PRC-004), but exempts
the Generator Owner from many of the standards applicable to a TO. The NERC Registry Criteria
defines the various functional entities. If a Generator Owner wants to own transmission facilities and
it falls under the definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions. Reliability gaps would
be better closed if select GOs and GOPs simply registered as TOs and TOPs. At this time, this would
not lead to a large number of extra registrations since, as stated in the technical justification
document, ‘interconnection requests for Generator Owner Facilities are still relatively rare.
No
See question 7 comments.
No additional comments.
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
Yes
Yes
Yes
Yes
No
see comment to Question 7
FMPA believes that TOP-004-2 R6.2 ought to also be addressed in the standards as applicable to
GOPs. The requirements reads: R6. Transmission Operators, individually and jointly with other
Transmission Operators, shall develop, maintain, and implement formal policies and procedures to
provide for transmission reliability. These policies and procedures shall address the execution and
coordination of activities that impact inter- and intra-Regional reliability, including: R6.2. Switching
transmission elements. Although planned outages are covered in other standards applicable to a GOP,
switching to close / synchronize a generator back to the system is not specifically covered in the
standards. Some have argued that TOP-002-2 R3 causes GOPs to coordinate its current day plans
with the TOP; however, the name of the standard is “Transmission Operations Planning” and therefore
implies the availability of the generator and related equipment and not necessary implies the policies
and procedures for switching operations; which includes synchronization. FMPA cannot imagine a
generator that would not have such switching / synchronization policies and procedures coordinated
with its interconnecting TOP; as such would normally be required through a Large Generator
Interconnection Agreement through a pro forma OATT; however, FMPA is not aware of any instance in
the standards that covers this. As such, FMPA recommends including TOP-004-2 R6.2 as being
applicable to a GOP.
see response to Question 7
Group
Dominion
Mike Garton
Yes
Yes
No
Dominion suggests in FAC-003-X; 4.3.1. Regional Entity be changed to RE as listed in 4.2.1 for
consistency. Also Regional Entity is used throughout the rest of the document, suggest using RE for
consistency overall. Dominion suggests in FAC-003-3; 4.3.1. adding station to the following “
Overhead transmission lines that extend greater than one mile or 1.609 kilometers beyond the fenced
area of the generation station switchyard and are” to show consistency as it is written in FAC-003-X
4.3.1. Further, Dominion is concerned that the technical justification characterized the exclusion (i.e.,
one mile or 1.609 kilometers beyond the fenced area of the generating station switchyard) as
“approximate line of sign [sic] from a fixed point” and notes that this line of sight may be limited by
local terrain. Where line of sight of the radial corridor is limited on a clear day due to terrain, the one
mile exemption must be limited in distance to no more than the line of sight on a clear day beyond
the fenced area.
Yes
Yes
Yes
Yes
Yes
No
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
The language for FAC-001 Requirement R2 should be: “This requirement shall apply to each
applicable Generator Owner. Generator Owner filings must be made at least 60 days in advance of
execution of the final interconnection study agreement in the Planning Coordinator’s or Transmission
Planner’s study process. Each applicable Generation Owner must publish its Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional Entity,
sub regional, Power Pool, and individual Transmission Owner planning criteria and Facility connection
requirements. The evaluation of the reliability impact(s) of interconnecting a third party Facility to the
Generator Owner’s existing Facility utilized for interconnection to the Transmission System must be
documented.”
Individual
Ed Davis
Entergy Services
Yes
Yes
Yes
We suggest that the Vegetation Management Standards should be consistent for both the TO and GO
facilities. We would also like to suggest an additional Recommendation for added clarity regarding
Category 3 Outages (Off-ROW Fall-in Outages). We understand that the Category 3 Outages are not a
violation of the Standard, but we feel that there should be some level of comment added within the
Standard clearly stating that these Outages are “Reportable Only” during the Quarterly Outage
reports to the RE’s, and that there are no associated violations/sanctions for this Category Of Outage,
and that an Off-ROW fall-in outage would not be considered an encroachment into the MVCD in any
way. The Technical Reference Document does a good job of clearly stating this in the Introduction on
Page 5 (“This standard is not intended to address outages such as those due to vegetation fall-ins or
blow-ins from outside the Right-of-Way, vandalism, human activities or acts of nature.”) and we feel
that this should also be stated clearly in the Standard.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Russell A. Noble
Cowlitz County PUD
Yes
Yes
Cowlitz PUD (District) registered as a Transmission Owner shortly before FAC-001-0 became effective
and was forced to file a Mitigation Plan in order to facilitate compliance. The District successfully
completed compliance implementation and documentation in eight months. The proposed one year
compliance timeframe is sufficient.
Yes
Yes
Yes
Yes
Yes
Yes
No
N/A
In answer to the SDT request for feedback on FERC's Order concerning Cedar Creek and Milford, the
District finds no technical reason to add any of the listed standard requirements, and struggles to
understand why FERC would even consider this listing as applicable.
Group
PPL NERC Registered Affiliates
Annette M. Bannon
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries and affiliates, appreciates the effort
by the Standard Development Team to address the GO-TO interface issues in a manner that enhances
the reliability of the BES without adding unnecessary burden on Generators. As registered GOs/GOPs,
the PPL Generation registered entities agree with the changes made by the SDT to these three
standards. To the extent that GOs/GOPs are required to register as TOs/TOPs, PPL Generation would
have significant concerns with meeting the compliance requirements applicable to TOs in the
standards included in the scope of this Project, as well as other TO/TOP requirements throughout
other NERC standards.
Group
Compliance & Responsbility Organization
Silvia Parada Mitchell
NextEra Energy, Inc. (NextEra) appreciates the work of the Project 2010-07 Generator Requirements
at the Transmission Interface Standard Drafting Team (SDT) on a subject that NextEra has a
significant interest in resolving. In fact, NextEra has been a member of the SDT and an active
observer. Given the recent events – such as (a) the North American Electric Reliability Commission's
draft interim directive; (b) the denial of the Milford and Cedar Cheek requests for reconsideration at
the Federal Energy Regulatory Commission (FERC) and (c) the record in this case which, at times,
suggests the SDT needs to more formally consider the Milford and Cedar Cheek Reliability Standards
– NextEra requests that SDT more formally consider the merits of each Reliability Standard adopted
the Milford and Cedar Cheek FERC orders and the NERC draft interim directive. Although NextEra does
not condone the manner in which NERC issued the interim draft directive and stated so in its
comments to NERC on the interim draft directive, NextEra’s overarching objective on this issue is to
bring a uniform, fair and technically supported approach that resolves the interface issue. Thus,
NextEra requests that the SDT (prior to proceeding any further or any additional comments or votes
on specific draft Reliability Standards) issue a technical paper that point-by-point addresses the
merits of including the Reliability Standards set forth in the FERC Orders and NERC’s draft interim
directive, and request stakeholder, including NERC staff, comment. For example, this technical paper
would likely the merits of NERC’s draft interim directive not requiring NERC-certified operators (but
require training of interface operators), while FERC’s orders require NERC-certified operators. While
NextEra does not agree five days of training is necessary for an interface operator, as the draft
interim directive appears to propose, NextEra does believe a technical case can be made why NERCcertification is not required, and that some degree of training related to the applicable Reliability
Standards is reasonable. Similar, on FAC-003 (as well as several other Standards), the draft interim
directive proposes a slightly different approach than the SDT. NextEra would rather these approaches
reconciled than be in conflict, with the potential for continued conflict as the SDT’s work product
proceeds. Further, NextEra requests that the SDT’s review the technical merits of NERC’s proposed
criteria to determine what generator transmission lead is required to comply with additional Reliability
Standards. As noted, above, this technical paper should be posted for stakeholder, including NERC
staff, comment. Accordingly, while NextEra would have preferred that NERC and the Regional Entities
express there interim draft directive approach on the record in this proceeding, NextEra believes it is
appropriate for the SDT to draft a comprehensive technical paper that, with an open approach,
considers the inclusion of additional Reliability Standards, if appropriate, as a way of building lasting
support for its approach.
Individual
Anthony Jablonski
ReliabiltiyFirst
ReliabilityFist has found a number of editiorial erros for the FAC-001-1 VSLs. They include the
following: 1. VSL R1 – should not reference sub-requirements, should reference the sub-parts
consistent with the requirement (i.e. Requirement R1, Part 1.1, 1.2 or 1.3) 2. VSL for R3 – the VSL
should referenced Requirement 3, Part 3.1.1 through 3.1.16 rather than what is currently stated
(Requirement R3, Part 3.1.1 R3.1.6)
Individual
Donald Jones
Texas Reliability Entity
No
In Section 5.1, the reference to Regional Entity should be removed. There are no requirements that
apply to the Regional Entity. In Requirements R1 and R4, “Planning Coordinator” should be added
after “Regional Entity.” In the ERCOT Region it is the Planning Coordinator that maintains planning
criteria and connection requirements. There is no NERC requirement or any obligation (as indicated in
the technical justification document) on the part of a GO to specifically execute an Agreement to
evaluate the reliability impact of interconnecting a third party Facility. Therefore, this requirement’s
applicability is contingent on a prerequisite that may not occur, and that is under the control of the
GO. This assumption on the part of the SDT unnecessarily complicates the compliance monitoring and
enforcement of this standard. For instance, if an “Agreement” is not executed, a GO is not required to
comply with the requirement, even though the GO may ultimately interconnect with another entity.
The requirement should be modified to include an applicability trigger similar to that of FAC-002-1, so
that once a GO “seek[s] to integrate . . .,” i.e., agrees to or is compelled to allow a third-party
interconnection, then the requirement becomes applicable. Otherwise, the compliance and monitoring
is subject to the SDT’s speculation as indicated in this language included in the technical justification
document: “However, the SDT cannot be certain this is the only example and it therefore proposes to
add this new requirement to FAC-001-1. In doing so, the SDT acknowledges that the Generator
Owner may not, at the time it agrees or is compelled to allow a third party to interconnect, have the
necessary expertise to conduct the required interconnect studies to meet this standard. Assuming
that a regulatory body would require a Generator Owner to evaluate such an interconnection request,
the SDT expects the Generator Owner and the third party to execute some form of an Agreement.”
Yes
In the description of the “second effective date” in FAC-003-X there is an erroneous reference to
“Requirement R3,” which should be corrected to “Requirement R1.”
No
A compliance timeframe for the applicable GOs of two years is too long and the scenario used as a
basis provides no timing specifics or details. Moreover, the 12 months for an existing transmission
line operated at 200kV or higher which is newly acquired by an asset owner and which was not
previously subject to this standard is arguably the same situation as an applicable GO but the
applicable GO has an additional 12 months to come into compliance.
Yes
No
Our negative votes on FAC-003 reflect our concern that this project has not considered all of the
applicable standards. Why did the SDT choose to only review the Ad Hoc Group’s standards when
there have been multiple registration appeals in which FERC and NERC have repeatedly cited specific
additional TO/TOP standards that were determined to be applicable to GO/GOPs? This SDT project
would serve a tremendous value to the ERO and in particular industry if it were to address the
technical aspects of the following FERC ordered applicable standards: PRC-001-1 R2, R4; PRC-004-1
R1; TOP-004-2 R6; PER-003-1 R1; FAC-003-1 R1, R2; TOP-001-1a R1 and FAC-004-2 R2. The SDT
team should analyze the FERC orders, the applicable standards indicated, and the circumstances and
facts involved, and technically justify why no reliability gap exists if these standards are not applied to
GO interface facilities. The SDT should include more “technical” information in its technical
justification document. For example, in regards to TOP-004-2 R7, the SDT technical justification
states that there is no reliability gap because, “. . . because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible.” An entity having a fiduciary obligation is
not a technical justification of why a reliability gap does not exist. Moreover, by that logic there would
be no need for many standards because every registered entity has a fiduciary obligation to protect
its facilities.
No
See comment 6.
No
See comment 6.
See comment 6.
Individual
Amir Hammad
Constellation Power Source Generation
Yes
Yes
Yes
Yes
Yes
Yes
Constellation supports the SDT justifications and offers additional information in our response to
question 10.
Yes
Yes
Constellation appreciates and supports the work of the standard drafting team. We recognize the
significant time invested by technical experts from industry to consider the appropriate application of
reliability standards to address concerns raised about coverage of transmission at the generator
interface. The drafting team analysis identified the standards in need of revision to appropriately
address the reliability concerns raised. While the revision process focuses on specific standards, it is
important to consider the reliability questions in the context of the full complement of reliability
standards that apply to entities. For instance, the following standards already apply to generators and
relate to the reliability considerations around transmission at the generator interface: • PRC-001-1
addresses coordination of protection system components by requiring all GOs to ensure coordination
of their protection system with interconnected parties. Further, FAC-002 requires that all new facilities
undergo reviews by the TOP, BA, etc. • PRC-004-1 requires all GOs to ensure that they analyze all
misoperations on their protection system which would include the protection of the tie line. • TOP
standards applicable to GOs aid coordination between a GO and a TO with regards to the generator tie
line by requiring all GOs to coordinate all maintenance and emergency outages (both forced and
planned) with all applicable interconnected parties. Further, all ISO procedures require the same of
GOs. • RC, TOP and/or BA certified operators control and are responsible for overseeing that
transmission. According to the NERC functional model, a Generator Operator is defined as
“operat(ing) generating unit(s) and perform(ing) the functions of supplying energy and reliability
related services.” Given this limited scope, the Generator Operator (GOP) cannot be considered as
operating on the same level as the Reliability Coordinator, Transmission Operator or Balancing
Authority when it comes to real time information on the status of the BES. The GOP does not monitor
and control the BES, rather the GOP only monitors and controls the generators that it operates and
relays information to other operating entities. • IRO and TOP standards applicable to GOs include tie
lines in their pool of resources to alleviate operational emergencies by requiring all GOs to operate as
directed by their TOP, BA, or RC as directed and must render emergency assistance. • FAC-8 and
FAC-9 manage rating methodology consistency by requiring all GOs to develop a methodology to rate
all equipment, and that the RC has the authority to challenge the GO on that methodology. The onus
is on the GO to either change their methodology and rating accordingly, or provide a technical
justification as to why they cannot adopt the changes. Further, a generator will never be limited by its
tie line, as a generator’s profits are directly tied to its output. Therefore no generator would limit its
facility to the equipment that is delivering that output.
Individual
Dennis Chastain
Tennessee Valley Authority
No
Suggest that the overall structure of the standard be revised such that R1 – R3 are applicable to the
Transmission Owner (consistent with existing FAC-001-0) and R4 (the new requirement) is applicable
to the “applicable Generator Owner”. See further comments below. Support the proposed revisions to
R1 and R4, but suggest R4 be returned to R3 (consistent with existing FAC-001-0). R3 in the balloted
standard should be returned to R2 (consistent with existing FAC-001-0) and only be applicable to the
Transmission Owner. R3.1 (or R2.1 if moved back) should be “fixed”, but it may be beyond this SDT’s
charge. The use of “above” in the FAC-001-0 standard, or the proposed reference to “Requirements
R1 or R2” in the proposed standard do not make sense in combination with the colon used at the end
of the requirement. Suggest that R3.1 (or 2.1 if moved back) be revised as written below and all sub-
requirements of R3.1 be elevated (R3.1.1 becomes R3.2, R3.1.2 becomes R3.3, etc.). “R3.1
Performance requirements and/or planning criteria used to assess system impacts.” R2 in the balloted
standard should become R4 and modified to incorporate the connection requirements contained in R3
that can more reasonably be expected of an “applicable Generator Owner”. For instance, an
“applicable Generator Owner” might simply have a connection requirement for a third party that
addresses coordination of system impact studies with the appropriate Transmission Owner(s), in lieu
of R3.1, R3.1.1, and R3.1.2. Suggest that R2 (or R4 if moved below existing FAC-001-0
requirements) be revised as written below. “R2 Each applicable Generator Owner that has agreed to
allow a third party Facility owner (Generation Facility, Transmission Facility, or End-user Facility) to
connect to the Transmission system through use of pre-existing applicable Generator Owner Facilities
shall communicate it’s Facility connection requirements to the third party. The applicable Generator
Owner Facility connection requirements shall address the following items: R2.1 Coordination of
system impact studies with the Transmission Owner. R2.2 Voltage level and MW and MVAR capacity
or demand at point of connection. R2.3 Breaker duty and surge protection. R2.4 System protection
and coordination R2.5 Metering….” Etc.
Yes
No comments
Yes
No
Group
Southern Company
Antonio Grayson
No
1) R4 is duplicative of R1 - either remove "maintain" from R1 or delete R4 - both instances of
"maintain" are not needed. 2) The measures, as written, provide no additional indication of the
evidence that could be presented to demonstrate compliance with the Reliability Standard
Requirements. They provide little guidance on assessing non-compliance with the Requirements.
No
See our response to Question 9.
No
All of these comments pertain to FAC-003-3: 1) We suggest referring to the Implementation Plan in
the Effective Date sub-section of Section A of the standard rather than repeating the content of the
Implementation Plan in the standard. There exists unnessary duplication with including the
information in both places. 2) We suggest simplifying the purpose statement to more succinctly say
the intent, for example: "To maintain a reliable transmission system by managing vegetation located
on transmission rights of way to minimize vegetation encorachments and thereby minimize the risk of
vegetation related outages". If this change is not acceptable, at least change the phrase "preventing
the risk" to "minimizing the risk". 3) We feel that the Enforcement paragraphs between 4.3.1.3 and
5.0 seem to be out of place. Those paragraphs don’t belong in this location - consider moving them to
Section C. Compliance. The fourth paragraph belongs in the background section. 4) We suggest
moving the background section to Section F. "Associated Documents". It gets in the way of getting to
the requirements of the standard. 5) We suggest moving Table 2 of the "Guideline and Technical
Basis" document into R1, since it seems to be the only part of the document that is enforceable.
Further we suggest that the Guideline and Technical Basis document be removed from the standard.
The inclusion of this document in the standard makes the standard unweildy. 6) We suggest
reordering the words in R1 to more clearly state the requirement. Please consider this rephrasing:
"For lines which are either an element of an IROL or an element of a Major WECC Transfer Path, each
applicable TO and applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within their Rating during all Rated Electrical Operating
Conditions of the types shown below:…" (remainder is unchanged). 7) We suggest reordering the
words of R2 to more clearly state the requirement. Please consider the this rephrasing: "For lines
which are neither an element of an IROL nor an element of a Major WECC Transfer Path, each
applicable TO and applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within its Rating and during all Rated Electrical Operating
Conditions of the types listed below:…" (remainder is unchanged). 8) On Page 11 of the posted clean
draft standard, is the reference to the previous footnote 2 correct? We recommend eliminating
footnotes where possible to minimize redirections. 9) The Rationale text-box on page 13 of the clean
version of FAC-003-3 overlaps some of the text of footnote #6.
Yes
The development of a working TVMP will take some time to initialize. The 1 year time frame for R3 is
appropriate. The 2 year time frame for all other requirements is appropriate.
No
We believe that a standard development process should not have parallel paths where the same
version is being modified by multiple teams. The uncertainty in which development path leads to
confusion in the industry and ultimately proves to have wasted come resources for the path that does
not come to fruition.
Yes
Additional responses are needed to justify the exclusion of the list of requirements and standards
found in the recent FERC order denying the rehearing request of the Compliance Registry Appeals of
Cedar Creek and Milford. (135 FERC Para. 61,241). Please see our response to Question 10 for a
detailed discussion on this topic.
No
We don’t believe the effort realizes the goal because 1) it is inclusive of FAC-001 that does not need
any modifications and 2) the effort needs to reinforce the appropriate justification not to include the
additional standards FERC has identified in their Cedar Creek and Milford Orders.
Yes
The version history table is incorrect - change version 3 to version 2.1.
Yes
Southern does not think that the revision to FAC-001-1 is necessary. A Generator Owner (GO)
cannot assess reliability impacts to the Bulk Electric System (BES) and determine acceptability
without support and involvement of the applicable owner and operator of the Transmission System
(i.e., the “interconnected TO” or “interconnected TP”). A generator tie-line does not equate to a
Transmission System. A GO must already adhere to a TO’s Facility connection requirements whether
the GO wants to connect additional facilities or a third parties’ facilities to its own interconnection
Facilities. Stated another way, the GO does not need Facility Connection requirements to govern how
multiple units are tied to a collector bus so why are they needed for a third party to connect to an
existing tie-line? In either case it is the interconnected TO or interconnected TP that has connection
requirements that must be fulfilled. The GO’s Interconnection Agreement would prohibit it from
connecting additional facilities without a new application for Interconnection Service with its
interconnected TO or interconnected TP. A GO should not need to develop “connection requirements”
unless it is in the business of owning and operating facilities independently of its interconnected TO or
interconnected TP. We do not believe a reliability gap exists in FAC-001-1 because the requestor for
interconnecting another Facility to an existing generation Facility must coordinate with the applicable
TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable facility connection
and performance requirements. If and when there is an agreement in place for a third party to
connect to a generator tie-line then the tie-line would become part of the integrated system and its
purpose and the owner’s function would likely warrant registration as a TO/TOP and FAC-001 would
then apply. The following excerpt from the 2010-07 Background Resource White Paper acknowledges
that this may be necessary: “The drafting team also acknowledges that, if another party interconnects
to a Facility owned by a Generator Owner, there may be the need to address MOD or TPL standards.
However, the drafting team believes that this, too, is best handled through specific evaluation,
perhaps accompanied by changes to the compliance registry. Entities that face this kind of scenario
may also meet criteria applicable to other registrations such as Transmission Service Provider or
Transmission Planner.” [Arguments related to jurisdictional, interconnection policy and open access
transmission tariff issues] (1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access transmission tariff
(OATT), a GO should not be required to comply with FAC-001-1 until that GO’s generating Facility
reaches commercial operation. NERC should not make facilities subject to the mandatory reliability
standards before the facilities are actually part of the BES. (a) Jurisdiction under FPA Section 215.
First, it is not clear that NERC or FERC has jurisdiction under FPA Section 215 to require generation
facilities that have not actually reached commercial operation to be subject to reliability standards.
Section 215(a)(2) of the FPA defines the “Electric Reliability Organization” as “the organization
certified by the Commission … the purpose of which is to establish and enforce reliability standards for
the bulk-power system, subject to Commission review.” Further, (a)(3) provides that “The term
‘reliability standard’ means a requirement, approved by the Commission under this section, to provide
for reliable operation of the bulk-power system. The term includes requirements for the operation of
existing bulk-power system facilities … the design of planned additions or modifications to such
facilities to the extent necessary to provide for reliable operation of the bulk-power system ….” Thus,
under Section 215 NERC can develop reliability standards that address requirements for existing bulkpower system facilities (i.e., facilities that have reached “commercial operation”) and for the design of
planned additions or modifications. It is logical to interpret the phrase “design of new facilities” as
meaning that new facilities must be designed to comply with existing reliability standards. However, it
is not clear that this provision should be interpreted as requiring that a generating facility that has not
yet reached commercial operation should be subject to reliability standards (including audit and
penalties). Therefore, the GO with the existing generation facilities should not be required to
incorporate the proposed generation facility into its Facility connection requirements before the
proposed generation facility is subject to NERC or FERC jurisdiction. (b) FERC’s interconnection policy.
In addition, the revised FAC-001 would appear to place restrictions on interconnection customers in
contravention of Order Nos. 2003 and 2006 (Standard Large and Small Interconnection Procedures
and Agreements). FERC was very concerned about the ability of interconnection customers to
interconnect their generating facilities and gave them a fair amount of flexibility. However, this
revised FAC-001 would appear to restrict some of this flexibility. (i) Order No. 2003 gives the
interconnection customer the ability to terminate a proposed interconnection on ninety days notice.
Therefore, the interconnection customer is not required to build the facility. However, this revised
FAC-001 appears to assume that the interconnection customer does not have this flexibility. What if
the interconnection customer (the GO building a new generator on its site or the third party building a
new generation facility) decides to terminate the Large Generator Interconnection Agreement (LGIA)
or not proceed with the generation facility? In such event, the GO may be required to revert to its
previous Facility connection requirements in order to accommodate the original configuration. (ii) The
LGIA permits modifications to the proposed interconnection. How would this affect the Facility
connection requirements? How long would the GO have to revise its Facility connection requirements?
In the event that there is a single modification, or perhaps multiple modifications, how does the GO
stay in compliance with this standard? (iii) FAC-001-1, R4 provides that each GO with Facility
connection requirements and each TO shall maintain Facility connection requirements and make
documentation of these requirements available to users of the Transmission System upon request.
However, Large Generator Interconnection Procedures (LGIP), Section 3.4 requires the posting of
certain interconnection information but the identity of the interconnection customer is not to be
disclosed (unless it is an Affiliate). Requirement R4 would appear to potentially require disclosure of
information and (more importantly) of the interconnection customer's identity in contravention of the
requirements in Order No. 2003 and the LGIP. (c) OATT requirements. The definition of “applicable
Generator Owner” (Section 4.2.1) and Requirement R2 provide that the GO will have an executed
Agreement to evaluate the impact of interconnecting a new facility to the GO’s existing generation
facility. This statement is ambiguous. This statement could be understood to mean that the GO of the
existing generation Facility will enter into an Agreement with the GO proposing to interconnect and
the existing GO will evaluate the impact of the proposed interconnection. However, requests to
interconnect new generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the new facility.
Thus, the language in FAC-001-1 would need to be revised to clarify that the owner of the new facility
will need to interconnect under the OATT of an appropriate Transmission Provider (i.e., the
Transmission Provider to which the existing GO is interconnected, not with the existing GO).
Therefore, the owner of the new facility will most likely be the entity with the executed Agreement
(with the Transmission Provider). Another consideration is that the existing GO could be developing a
merchant transmission line. In that case, the existing GO would need to evaluate whether it needs
have its own OATT and OASIS. In that case, the new generator owner would be interconnecting to the
existing GO. However, the existing GO’s line would not be a generator tie-line. This issue is not clear
from the draft standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES reliability…” (b) It is
unclear in Applicability section 4.2.1 that the term “Agreement” means that the GO has an executed
agreement with a TO/TSP or that the GO and the third party have an executed agreement. Without
further explanation, the capitalized term “Agreement” has the effect of introducing confusion. If the
SDT does not intend to propose a new addition to the NERC Glossary of Terms, it should use the
lower case term, “agreement.” With respect to the capitalized term, “Transmission System,” the SDT
should consider clarifying if it intends to propose adding this to the Glossary. (3) Effect of the
proposed revisions to FAC-001-1 on FAC-002-1. (a) As drafted, there are scenarios under which a
new GO may attempt to interconnect to an existing GO even though, as explained above, the
interconnection should actually be done to the appropriate Transmission Provider. If the appropriate
Transmission Provider is not included in the evaluation of the interconnection various types of harm
may occur. In such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002. (b) FAC-001 and FAC-002 should be revised to
be clear that the existing GO and any new GOs must coordinate any interconnection with the
appropriate Transmission Provider, TP and PA.
We agree with the 2010-17 Standard Drafting Team’s conclusion to not modify other standards such
as those mentioned on page 4 of the Technical Justification document. In additon, we wish to provide
the following support for exclusion of these specific standards. Southern Company believes NERC’s
Project 2010-07 SDT must challenge making revisions to the standards included in the FERC order on
Cedar Creek and Milford. (This order supports NERC’s requirement for those entities to register as a
TO/TOP due to their ownership of generator interconnection circuits > 100kV.) We believe there are
clear technical and reliability-based reasons that support not adding GO and GOP requirements to
these standards and not requiring the GO or GOP to register as a TO or TOP. Furthermore, we also
believe there are clear distinctions between GO/GOP responsibilities and TO/TOP responsibilities that
must be maintained to ensure BES reliability. Revising standards to assign TO/TOP responsibilities to
a GO/GOP or requiring a GO/GOP to register as a TO/TOP because of generator interconnection
circuits > 100kV will reduce the clarity of these responsibilities. We have provided specific comments
on each standard below: EOP-005-1 R1, R2, R6, R7 R1 and R2 require each TOP to have and maintain
a system restoration plan. R6 requires the TOP to train its operating personnel in implementing this
plan. R7 requires the TOP to verify its restoration plan by actual testing or simulation. These
requirements are clearly the role and responsibility of the TOP, not a GO/GOP who happens to have
generator interconnection facilities in the TOP’s control area. The GOP’s roles and responsibilities are
clearly and appropriately addressed EOP-005-2. The presence of a generator interconnection circuit >
100kV that happens to be owned by the GO instead of the TOP fundamentally does not change the
roles and responsibilities of the TOP or the GOP. Thus, no changes due to EOP-005 are needed. FAC014-2, R2 FAC-014-2 R2 states “The Transmission Operator shall establish SOLs (as directed by its
Reliability Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its
Reliability Coordinator’s SOL Methodology.” FAC-014-2 R2 should not be revised to include GOPs. The
GO is required by FAC-008-1 R1 and FAC-009-1 (FERC approved version) and pending FAC-008-3 R3
and R6 (FAC-008-3 filed with FERC for approval) to document the Facility Ratings for a GO-owned
generator interconnection circuit >100kV. The established Facility Rating must respect the most
limiting applicable equipment rating in the circuit and must consider operating limitations and ambient
conditions. The thermal or ampere rating of this circuit would equal its ampere operating limit and
should be conveyed by the GO to the GOP if they are not the same entity. The operating voltage
limits for this circuit are established by the applicable TO/TOP, not the GO or GOP. Therefore, we
believe adding the GO to FAC-014-2 R2 would be redundant. PER-003-1 R2, R2.1, R2.2 PER-003-1 R2
and its sub-requirements state: “R2. Each Transmission Operator shall staff its Real-time operating
positions performing Transmission Operator reliability-related tasks with System Operators who have
demonstrated minimum competency in the areas listed by obtaining and maintaining one of the
following valid NERC certificates (1 ) : [Risk Factor: High][Time Horizon: Real-time Operations]: R2.1.
Areas of Competency R2.1.1. Transmission operations R2.1.2. Emergency preparedness and
operations R2.1.3. System operations R2.1.4. Protection and control R2.1.5. Voltage and reactive
R2.2. Certificates • Reliability Operator • Balancing, Interchange and Transmission Operator •
Transmission Operator This requirement is specifically for TOPs. Personnel training for GOPs needs to
be addressed separately and not mingled with responsibilities of the TOP. The GOPs role in supporting
BES reliability needs to be clearly understood and defined prior to establishing training requirements
in the standards. PRC-001-1, R2, R2.2, R4, R6 Generator Operators (GOPs) and the scope of
protection equipment for generation interconnection Facilities are already appropriately accounted for
in this standard in requirement R2 and sub-requirement R2.2 The language used in requirement R2
which applies to the GOP uses the general terms “relay or equipment failures” which would include
not only generator relaying, but generator interconnection relaying in the GOPs scope as well. The
GOP is required to notify the TOP and Host BA in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected TOP to notify its RC and affected
TOPs and BAs. Thus, applying R2.2 to a GOP would be redundant to R2.1. Requirement R4 states,
“Each Transmission Operator shall coordinate protection systems on major transmission lines and
interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.” A generator interconnection tie line does not constitute a ‘major tie line” or major
“interconnection with neighboring GOPs, TOPs, and BAs.” Thus, R4 should not be revised to include
GOPs. If a GO exists within NERC that does own such interconnection facilities, the responsibility for
coordination of protection systems on such a line or interconnection should be the responsibility of the
TOP in that area, not the GO/GOP. This may require formal agreements between the TO/TOP and
GO/GOP, since the GO may own protection equipment on his end. The same logic applies to R6. R6
states, “Each Transmission Operator and Balancing Authority shall monitor the status of each Special
Protection System in their area, and shall notify affected Transmission Operators and Balancing
Authorities of each change in status.” This is clearly the responsibility of the TOP and/or BA, not a
GO/GOP who happens to have generator interconnection facilities in the area. An SPS function by
definition is to maintain BES reliability. If a GO/GOP has equipment within the equipment scope of a
Special Protection System (SPS), responsibility for monitoring the SPS should be conveyed in a formal
agreement as appropriate. TOP-001-1 R1 Requirement R1 states, “Each Transmission Operator shall
have the responsibility and clear decision-making authority to take whatever actions are needed to
ensure the reliability of its area and shall exercise specific authority to alleviate operating
emergencies.” This is clearly the responsibility of the TOP, not a GO/GOP who happens to have
generator interconnection facilities in the TOP’s area. Thus, R1 should not be applied to a GO/GOP
who owns or operates generator interconnection facilities. Furthermore, TOP-001-1 R3 (proposed to
be covered in the future in the proposed IRO-001-2 R2 and R3) appropriately requires the GOP to
comply with reliability directives issued by the TO “unless such actions would violate safety,
equipment, regulatory or statutory requirements.” These requirements effectively give the TOP the
necessary decision-making authority over operation of all generator Facilities up to the point of
interconnection. They also give the GOP the necessary authority to take appropriate actions to ensure
safety and protection of the GO’s equipment. Thus, no changes to TOP-001-1 are necessary. TOP004-2 R6, R6.1, R6.2, R6.3, R6.4 Requirement R6 and its sub-requirements state: “R6. Transmission
Operators, individually and jointly with other Transmission Operators, shall develop, maintain, and
implement formal policies and procedures to provide for transmission reliability. These policies and
procedures shall address the execution and coordination of activities that impact inter- and intraRegional reliability, including: R6.1. Monitoring and controlling voltage levels and real and reactive
power flows. R6.2. Switching transmission elements. R6.3. Planned outages of transmission elements.
R6.4. Responding to IROL and SOL violations.” These are clearly the responsibility of the TOP, not a
GO/GOP who happens to have generator interconnection facilities in the TOP’s area. Thus, these
requirements should not be applied to a GO/GOP who owns or operates generator interconnection
facilities. The same logic applies here as stated above in our discussion on TOP-001-1. We believe it is
inappropriate and would be adverse to BES reliability to apply these requirements to a GOP. TOP-0042 effectively gives the TOP the necessary decision-making authority over operation of all generator
Facilities up to the point of interconnection. They also give the GOP the necessary authority to take
appropriate actions to ensure safety and protection of the GO’s equipment, such as opening high
voltage generator output breakers when required to protect the unit. Thus, no changes to TOP-004-2
are necessary. TOP-006-2 R3 Requirement R3 states, “R3. Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall provide appropriate technical information concerning
protective relays to their operating personnel. The intent of this requirement when applied to a GOP is
already addressed in PRC-001-1 R1 which states, “Each Transmission Operator, Balancing Authority,
and Generator Operator shall be familiar with the purpose and limitations of protection system
schemes applied in its area.” Thus, no change to TOP-006-2 is necessary.
Group
ACES Power Marketing Standards Collaborators
Jason Marshall
Yes
We largely agree with the changes the drafting team made but believe some additional changes are
necessary. In section 4.2.1 of the Applicability Section, “within” should be “with”. Because NERC’s
Glossary of Terms establishes that an Agreement can be verbal and not enforceable by law, section
4.2.1 should be further modified to clarify that it is a legally enforceable and fully executed
Agreement. The language in R3 in parenthesis after Generation Owner should be modified to “once
required by Requirement R2”. This makes it clearer that R3 does not apply until the GO has an
executed Agreement to evaluate a request by a third part to interconnect.
Yes
Yes
We support the changes to FAC-003 suggested by the drafting team because we believe the drafting
team has provided the best solution in face of a difficult problem. However, in general, we do not
support registration of GOs and GOPs as TOs and TOPs or applicability of any TO/TOP requirements to
the GO/GOP simply because they have a radial interconnection greater than one mile in length. While
there may be some generators that own interconnecting facilities of significant length operated at a
significant voltage that could impact BES reliability, we do not believe that the number of generating
facilities that fit into that category is significantly large. When one considers that the majority of
generators are still owned and operator by utilities that are also registered as a TO and TOP, there is
only a minority subset of generators left that could be considered. NERC has the registration for this
remaining set of generators and could use the data to evaluate how many of this remaining subset
have interconnections owned by the generator that are substantial enough to affect reliability. It
seems that NERC could determine the boundaries of this problem before registering anymore GOs and
GOPs as TOs and TOPs or before applying additional requirements through this effort on the GOs and
GOPs.
Yes
Yes
With recent NERC BOT approval of the FAC-003-2 standard, the drafting team should continue to
monitor the standard progress with FERC and make necessary adjustments to the implementation
plan.
Yes
Yes
No
The modifications are largely the appropriate ones with the exceptions we noted in Q1 and Q10.
The modifications to PRC-004-2.1 R2 could be interpreted as requiring the GO to analyze Protection
System Misoperations on the generator interconnection Facility even if it does not own the Facility.
We suggest modifying the requirement as shown below to address this issue. “The Generator Owner
shall analyze Protection System Misoperations on its generator and generator interconnection Facility
that it owns …”
Group
Western Electricity Coordinating Council
Steve Rueckert
No
WECC casts an affirmative vote for the SDT proposal as a necessary but not sufficient step in
addressing the GOTO matter. WECC, NERC, and the other Regions developed a subset of Standards
and Requirements that were considered necessary to address potential gaps for transmission
interconnection facilities and operations to be included in a proposed NERC Directive, which is
expected to issue by year-end. The subset of requirements developed for the proposed NERC
Directive were informed by the applicable FERC Orders. Consequently, it is important that the SDT
address the comparative reliability risks between the proposed NERC Directive List and the SDT
Proposal to assure that reliability gaps will not result from the SDT proposal. Please see NERC’s
proposed Directive for the rationale and technical justification.
PLease see response to question #7.
See additional comments received attached.
Additional Comments Received
Generator Requirements at the Transmission Interface (Project 2010-07)
NERC Comments:
1. Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.)
Yes
No
Comments:
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1?
Yes
No
Comments: There appears to be no rationale for allowing one year for the development of
connection requirements given the Technical Justification rationale that the compliance clock
starts “if and only if when it executes an Agreement to evaluate…..”, recognizing the time lag
indicated in the Technical Justification.
3. With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003.
Some commenters found the half-mile length too short, others found it too long, and still others
found the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one
mile beyond the fenced area of the generating station switchyard…” We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point
(at the fenced area of the generation station switchyard) eliminates confusion and any
discretion on the part of a Generator Owner or an auditor. Finally, we maintain that it is
appropriate to include this qualifier for Generator Owners because there is a very low risk from
vegetation within the line of sight, and thus the formal steps in this standard are not necessary
to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented,
a decision that will be made as Project 2007-07—Vegetation Management moves forward, do
you support the proposed redline changes to FAC-003-X and FAC-003-3?
Yes
No
Comments:
4. Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X?
Yes
No
Comments:
5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here.
Yes
No
Comments:
6. In its technical justification document, the SDT reviews all standards that had been proposed
for substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Yes
No
Comments: Please see the comments to Question 7 for the rationale for expanding the scope of
the SDT to address additional Standards.
7. The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the
set of standards currently posted achieve this goal?
Yes
No
Comments:
Regarding Project 2010-07 Generator Requirements at the Transmission Interface, NERC staff
advises the SDT revisions to the following Standards must be included, for all facilities that are
deemed to be ‘BES Transmission Facilities more commonly described as Generator Leads’:
a) EOP-005-1 R1, R2, R5, R6 and R7
Revisions to this Standard are needed to respond to:
• If GOP has blackstart resources defined by its RC, then EOP-005 applies. The GOP
restoration plan would require coordination with TOP per the TOP Blackstart
Restoration Plan. The GOP would start its blackstart resources to provide necessary
real and reactive power to its generating resources per interconnecting TOP
directives. (Note: In addition, if GOP has blackstart capability the interconnection
TOP will have included this capability in its restoration planning for its area of
responsibility.)
•
If GOP does not have blackstart resources, GOP restoration plan is dependent upon
provision of real and reactive power service from interconnecting TOP, per VAR-001
and VAR-002 requiring the GOP to follow the directives of the interconnecting TOP,
compliance with this standard/requirments is not required.
b) FAC-014-2 R2
If the Transmission system has associated SOLs as directed by its RC, the applicable GOP
shall establish these limits per the RC‘s direction
c) PER-002-0
In order that the requirements of PER-003-0 are not applied, PER-002 should be revised to
require the applicable GOP should develop an appropriate training program that contains the
necessary elements for the GOP operating their Transmission facility to understand fully the
impacts of operation on the BES; such as a) equipment involved, including protection
systems, b) the coordination aspects with the TO/TOP to which it is connected, and c) the
protocols for and impacts of operating facilities associated with a Transmission facility. The
objective of this training is to ensure that the GOP is completely aware of its obligations to
have the ability to follow the directives of the appropriate TOP. This ability includes
personnel with the skills and training to execute these obligations in the best interest of
reliability concerning the reliable operational and coordination issues with the
interconnecting TOP.
Therefore, for all generators that are determined to be a typical Generator Long Lead type
facility, revising PER-002 would provide a method that recognizes full NERC Certification
of operators at these type generators is unnecessary to bridge the reliability gap that exists
until all appropriate Reliability Standards are revised to incorporate the proper wording. The
basis of this conclusion is through a rudimentary technical evaluation of the topics required
for full NERC Certified Operator initial certification. This review resulted in only 25% of the
topics included in the certification testing requirements would generally apply to operators at
a typical Generator Long Lead type facility. Consequently, revising PER-002 would provide
adequate training that will meet the facts and circumstances of each specific generator and as
such bridges the reliability gap.
A component of this training might be NERC Technical Reference Document ‘Power Plant
and Transmission System Protection Coordination’.
(http://www.nerc.com/docs/pc/spctf/Gen%20Prot%20Coord%20Rev1%20Final%2007-302010.pdf)
d) PRC-001 In order to avoid confusion, revise R1 to require the applicable GO to maintain,
and the applicable GOP, to monitor those systems defined as BES Transmission metering
and protection circuits/systems above and beyond the Generation equipment metering and
protection circuits/systems; and R4 to coordinate Transmission protection systems with the
interconnection TOP’s protection system that apply.
e) PRC-005 In order to avoid confusion, revise the Standard R1 to require the applicable GO to
develop a program which includes those maintenance and testing intervals and a summary of
procedures for those systems defined as BES Transmission metering and protection
circuits/systems above and beyond the Generation metering and protection circuits/systems.
f) TOP-001-1 R1 Applicable GOPs assigned to operate their BES Transmission facilities have
clear and unambiguous authority to operate those facilities.
g) TOP-004-2 R6 Applicable GOPs to develop formal policies and procedures that provide for
coordination of activities associated with their Transmission facilities that may impact
reliability with their interconnecting TOP and/or GOPs identified in FAC-001
h) TOP-006-1 R3 Applicable GOPs provide appropriate technical information concerning
Transmission metering and protection circuits/systems to their operating personnel.
8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting
the appropriate ones?
Yes
No
Comments: See full comments in Question 7
9. If you answered “no” to Question 7, what standards need to be added or removed to achieve
the SDT’s goal? Please provide technical justification for your answer.
Yes
No
Comments: See full comments in Question 7 and also refer to question 6 and the reference to
the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface, dated Nov 16, 2009
10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Yes
No
Comments:
Notwithstanding the comments in the SDT’s Technical Justification paper relative to work within
other existing or future Standard Development Projects, we advise this SDT to expand its scope to
include the above listed necessary Standards revisions.
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments for Project 2010-07—Generator Requirements at the Transmission Interface.
These standards were posted for a 45-day public comment period from October 5, 2011 through
November 18, 2011. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 40 sets of comments, including
comments from 123 different people from approximately 86 companies representing all 10 of the
Industry Segments as shown in the table on the following pages.
Based on stakeholder comments, the SDT made minor changes to FAC-001-1, FAC-003-X, FAC-003-3,
and PRC-004-2.1. The standards will proceed to recirculation ballot.
In FAC-001-1, the SDT corrected a typo in the Applicability section 4.2.1 to change “within” to “with”;
corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather
than just 3.1.1 through 3.1.6; and changed references to “Transmission System” to “interconnected
Transmission systems” to ensure consistency with the language elsewhere in the standard and in FAC002-1.
In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO exemption
in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and changed “RE” to
“Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements
at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either
(1) staffed and the overhead portion is within line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting these Facilities because
incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and appropriate risk prevention
approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead
transmission lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the
generating switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has
been agreed upon by the stakeholder body. In its Consideration of Comments report from the last
formal comment period, which ended on July 17, 2011, the SDT explained “We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the part
of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference here, the
SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Members of the ballot pool should note that for its recirculation ballot, the SDT will be balloting both
FAC-003-3 and FAC-003-X, but stakeholders should not vote as though they are choosing one or the
other. The SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved
by FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually.
In other words, stakeholders who support adding GOs to the applicability of FAC-003 should vote in
the affirmative for both FAC-003-3 and FAC-003-X.
In PRC-004-2.1, the SDT added a reference to the generator interconnection Facility to the data
retention section of the standard (for consistency with the language in R2) and corrected a typo in the
Version History.
Several commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same
explicit reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT
agrees and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation
ballot posting) soon.
Many commenters encouraged the SDT to reexamine the standards and requirements addressed in
FERC’s Milford and Cedar Creek orders and NERC staff’s draft compliance directive regarding generator
lead lines. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or draft NERC directives, within the standards process,
and until this round of comments, when NERC staff submitted comments, the SDT had no formal
mandate that would have made it appropriate to consider the content of the proposed directive.
The SDT reviewed all addressed standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these
standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder
concern, the SDT has expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or
by NERC in its draft compliance directive.
Other minority comments are addressed within specific questions below.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
2
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.) …. .............................................................. 12
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1? …. ........................................................................................... 29
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some
commenters found the half-mile length too short, others found it too long, and still others found
the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its
latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile
beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the
part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this
qualifier for Generator Owners because there is a very low risk from vegetation within the line of
sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a
decision that will be made as Project 2007-07—Vegetation Management moves forward, do you
support the proposed redline changes to FAC-003-X and FAC-003-3? …. ....................................... 34
4.
Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X? …. ......................................................................................... 50
5.
In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here. …. ...................................................................................... 57
6.
In its technical justification document, the SDT reviews all standards that had been proposed for
substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for any
of these decisions, please include suggested language here. …. ..................................................... 63
7.
The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
4
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the set
of standards currently posted achieve this goal? …. ......................................................................... 74
8.
If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the
appropriate ones? ….......................................................................................................................... 87
9.
If you answered “no” to Question 7, what standards need to be added or removed to achieve the
SDT’s goal? Please provide technical justification for your answer. …. ............................................ 91
10. Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 99
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
5
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Gerald Beckerle
SERC OC Standards Review Group
1.
Scott Brame
NCEMC
2.
Troy Willis
Georgia Transmission Corp. SERC 1
3.
Mike Hirst
Cogentrix
SERC 5
4.
Bob Dalrymple
TVA
SERC 1, 3, 5, 6
5.
Matt Carden
Southern Co.
SERC 1, 5
6.
Shardra Scott
Gulf Power Co.
SERC 3
7.
Kerry Sibley
Georgia Transmission Corp. SERC 1
8.
Andy Burch
EEI
SERC 5
9.
Shaun Anders
City of Springfield (CWLP)
SERC 1, 3
SERC 1, 3, 5
11. John Troha
SERC 10
2.
Group
Jonathan Hayes
X
Southwest Power Pool Standards
Development Team
Additional Member Additional Organization Region Segment Selection
3
X
SERC 1, 3, 4, 5
10. Melinda Montgomery Entergy
SERC Reliability Corp
2
X
4
5
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Jonathan Hayes
Southwest Power Pool
SPP
2
2.
Robert Rhodes
Southwest Power Pool
SPP
2
3.
Don Taylor
Westar
SPP
1, 3, 5, 6
4.
John Allen
City Utilities of Springfield
SPP
1, 4
5.
Sean Simpson
MCPBPU
SPP
1, 3, 5
6.
Louis Guidry
CLECO
SPP
1, 3, 5
7.
Mitch Williams
Western Farmers
SPP
1, 3, 5
8.
Valerie Pinnamonti
AEP
SPP
1, 3, 5
9.
Bud Averill
Grand River Dam Authority SPP
1, 3, 5
OGE
1, 3, 5
10. Terri Pyle
3.
Group
SPP
Guy Zito, Guy Zito
Additional Member
2
3
4
5
6
7
Northeast Power Coordinating Council,
Northeast Power Coordinating Council
Additional Organization
Region
Alan Adamson
New York State Reliability Council, LLC
NPCC, NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC, NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC, NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC, NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC, NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC, NPCC 2
9.
Chantel Haswell
NPCC, NPCC 10
FPL Group, Inc.
NPCC, NPCC 5
10. David Kiguel
Hydro One Networks Inc.
NPCC, NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC, NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC, NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC, NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC, NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC, NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC, NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC, NPCC 5
18. Saurabh Saksena
National Grid
NPCC, NPCC 1
19. Michael Schiavone
National Grid
NPCC, NPCC 1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
10
X
Segment Selection
1.
8
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
20. Wayne Sipperly
New York Power Authority
NPCC, NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC, NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC, NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC, NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 3
4.
Group
Emily Pennel
No additional members listed.
Southwest Power Pool Regional Entity
5.
MRO NSRF
Group
Will SMith
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Jodi Jenson
WAPA
MRO
1, 6
4.
Ken Goldsmith
ALTW
MRO
4
5.
Alice Ireland
XCEL/NSP
MRO
1, 3, 5, 6
6.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
7.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
8.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
9.
Scott Nickels
RPU
MRO
4
10. Terry Harbour
MEC
MRO
1, 3, 5, 6
11. Marie Knox
MISO
MRO
2
12. Lee Kittelson
OTP
MRO
1, 3, 4, 5
13. Scott Bos
MPW
MRO
1, 3, 5, 6
14. Tony Eddleman
NPPD
MRO
1, 3, 5
15. Mike Brytowski
GRE
MRO
1, 3, 5, 6
16. Richard Burt
MPC
MRO
1, 3, 5, 6
6.
Group
Charles W. Long
Additional Member
Additional Organization
SERC Planning Standards Subcommittee
X
X
Region Segment Selection
1. Pat Huntley
SERC
SERC
10
2. John Sullivan
Ameren Services Co.
SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Bob Jones
Southern Company Services SERC
1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Jason Adams
7.
TVA
Group
SERC
Frank Gaffney
2
3
4
5
6
7
1
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
8.
Group
FRCC
Mike Garton
Additional Member
Dominion
Additional Organization
Region Segment Selection
1. Michael Gildea
Dominion Resources Services, Inc.
RFC
2. Connie Lowe
Dominion Resources Services, Inc.
NPCC 5, 6
3. Michael Crowley
Virginia Electric and Power Company RFC
9.
Group
Annette M. Bannon
Additional Member
Additional Organization
5, 6
1, 3
PPL NERC Registered Affiliates
Region Segment Selection
1. Brent Ingebrigston
LG&E and KU Services Co.
SERC
3
2. Don Lock
PPL Brunner Island, LLC
RFC
5
3.
PPL Martins Creek, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Montour, LLC
RFC
5
6.
Lower Mount Bethel Energy, LLC RFC
5
7. Annete Bannon
PPL Susquehanna, LLC
5
8. Leland McMillan
PPL Montana, LLC
10.
Group
Jason Marshall
Additional Member
Additional Organization
RFC
WECC 5
ACES Power Marketing Standards
Collaborators
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power
RFC
2. Erin Woods
East Kentucky Power Cooperative SERC
1, 3, 5, 6
3. Michael Brytowski
Great River Energy
1, 3, 5, 6
MRO
3, 5, 6
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11.
2
3
4
5
6
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
12.
Jack Cashin
Electric Power Supply Association
X
X
Individual
14. Individual
Natalie McIntire
Tom Flynn
American Wind Energy Association
Puget Sound Energy, Inc.
X
X
X
15.
Individual
Silvia Parada Mitchell
Compliance & Responsbility Organization
16.
Individual
Southern Company
Individual
Antonio Grayson
Chris Higgins/Stephen
Enyeart/Chuck
Mathews/Charles
Sheppard
18.
Individual
Thad Ness
American Electric Power
19.
Individual
BP Wind Energy North America Inc.
Individual
Carla Bayer
John Bee on behalf of
Exelon
Individual
Dennis Sismaet
Individual
Michelle D'Antuono
Seattle City Light
Ingleside Cogeneration LP (Occidental
Chemical)
23.
Individual
Michael Falvo
Independent Electricity System Operator
24.
Individual
Greg Rowland
Duke Energy
X
25.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
26.
Individual
Kirit Shah
Ameren
27.
Individual
John Seelke
Individual
29. Individual
30.
31.
Individual
13.
17.
20.
21.
22.
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Bonneville Power Administration
X
X
X
Exelon
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PSEG
X
X
X
X
Andrew Z. Pusztai
RoLynda Shumpert
American Transmission Company
South Carolina Electric and Gas
X
X
X
X
Individual
Ravi Bantu
RES Americas Development
Individual
Katy Wilson
Sempra Generation
28.
7
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Joe Petaski
Manitoba Hydro
X
X
X
X
Individual
34. Individual
Chris de Graffenried
Ed Davis
Consolidated Edison Co. of NY, Inc.
Entergy Services
X
X
X
X
X
X
X
X
35.
Individual
Alice Ireland
Xcel Energy
X
Individual
Russell A. Noble
Cowlitz County PUD
X
X
X
36.
X
X
37.
Individual
Anthony Jablonski
ReliabiltiyFirst
X
38.
Individual
Donald Jones
Texas Reliability Entity
X
39.
Individual
Amir Hammad
Constellation Power Source Generation
40.
Individual
Dennis Chastain
Tennessee Valley Authority
32.
Individual
33.
X
X
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
X
11
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and removed the Generator Owner
from R4. Do you support the proposed redline changes to FAC-001-1? (Please refer to the posted FAC-001-1 technical
justification document for more information about the SDT’s rationale for its changes.)
Summary Consideration:
The SDT thanks all stakeholders for their comments and their 87% approval for the FAC-001-1 changes posted for ballot
in November 2011. Based on stakeholder feedback, the SDT has made the following minor changes to FAC-001-1:
-Corrected a typo in Applicability section 4.2.1 to change “within” to “with.”
-Corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather than just 3.1.1
through 3.1.6.
-Changed references to “Transmission System” to “interconnected Transmission systems” to ensure consistency with the
language elsewhere in the standard and in FAC-002-1.
Some stakeholders remain concerned about the intent of the SDT’s work on FAC-001-1. The SDT reminded them that the
scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with ownership or
operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should first address
“low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”) – that
is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
Through its deliberations, the SDT concluded that an interconnection Facility owned or operated by a GO or GOP that is
more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
Concerned commenters were also referred to one of the SDT’s resource documents: Project 2010-07: Generator
Requirements at the Transmission Interface Background Resource Document.
Some commenters suggested changes to Requirements R1 or R4, which deal exclusively with the Transmission Operator
and are outside the scope of the SDT’s work.
One commenter suggested formatting changes. The SDT agrees with the commenter that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the
standard and no change was made.
One commenter suggested that the phrase “Generator Owner’s existing Facility” be changed to “Generator Owner’s
existing Transmission Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part because in
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
12
some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC.
Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain the
term “Transmission.”
One commenter did not agree with the overall clarifying change to the Applicability section, but the SDT reminded this
commenter that this change was made to address previous comments that indicated that there was uncertainty as to
whether “another Facility to its existing generation Facility” was meant to address connecting additional generators by
the same GO. The SDT intends FAC-001-1 to apply only when the GO of an existing Facility executes an agreement to
evaluate the reliability impact of connecting additional generation owned by another GO. No change made with respect
to this comment.
A few stakeholders were concerned with the 45-day time frame included in the standard. The SDT pointed out that
majority of stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would
simply need to adopt (document and publish) the Facility connection requirements of its TO. No change to that time
frame was made.
Organization
Yes or No
Question 1 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While
the Technical Justification document states that the SDT intended to focus
on a Generator Owner’s radial interconnection facilities, the scope of the
revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis would most likely be
outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Southern Company
No
1) R4 is duplicative of R1 - either remove "maintain" from R1 or delete R4 both instances of "maintain" are not needed.  2) The measures, as
written, provide no additional indication of the evidence that could be
presented to demonstrate compliance with the Reliability Standard
Requirements. They provide little guidance on assessing non-compliance
with the Requirements.  
Response: Thank you for your comment. We agree with your suggestions, but both are outside the scope of this SDT. These items
will be submitted to the Issues Database to be addressed in a future revision of FAC-001.
Southwest Power Pool Standards
Development Team
No
Based on the applicability section of FAC-001 we feel that the strike through
should have been kept. It limited the requirement to just those generator
owners who had agreements in place, which we feel is appropriate.
Response: Thank you for your comment. This change was made to address previous comments that indicated to the SDT there was
uncertainty as to whether this was meant to address connecting additional generators by the same GO. The SDT intends FAC-001
to apply only when the GO of an existing Facility executes an agreement to evaluate the reliability impact of connecting additional
generation owned by another GO. No change made with respect to this comment.
Texas Reliability Entity
No
In Section 5.1, the reference to Regional Entity should be removed. There
are no requirements that apply to the Regional Entity.
In Requirements R1 and R4, “Planning Coordinator” should be added after
“Regional Entity.” In the ERCOT Region it is the Planning Coordinator that
maintains planning criteria and connection requirements. There is no NERC
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
requirement or any obligation (as indicated in the technical justification
document) on the part of a GO to specifically execute an Agreement to
evaluate the reliability impact of interconnecting a third party Facility.
Therefore, this requirement’s applicability is contingent on a prerequisite
that may not occur, and that is under the control of the GO. This
assumption on the part of the SDT unnecessarily complicates the
compliance monitoring and enforcement of this standard. For instance, if
an “Agreement” is not executed, a GO is not required to comply with the
requirement, even though the GO may ultimately interconnect with another
entity. The requirement should be modified to include an applicability
trigger similar to that of FAC-002-1, so that once a GO “seek[s] to integrate .
. .,” i.e., agrees to or is compelled to allow a third-party interconnection,
then the requirement becomes applicable. Otherwise, the compliance and
monitoring is subject to the SDT’s speculation as indicated in this language
included in the technical justification document: “However, the SDT cannot
be certain this is the only example and it therefore proposes to add this new
requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a
third party to interconnect, have the necessary expertise to conduct the
required interconnect studies to meet this standard. Assuming that a
regulatory body would require a Generator Owner to evaluate such an
interconnection request, the SDT expects the Generator Owner and the
third party to execute some form of an Agreement.”
Response: Thank you for your comment. All of these comments are outside the scope of the SAR and the SDT’s work because they
refer specifically to the sections and requirements that apply to the TO alone. We encourage you to consider submitting a SAR that
addresses your concerns.
Manitoba Hydro
No
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
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Organization
Yes or No
Question 1 Comment
While the Technical Justification document states that the SDT intended to
focus on a Generator Owner’s radial interconnection facilities, the scope of
the revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
2) If the drafting team intends to limit the scope of FAC-001-1 to GO owned
radial generator interconnection facilities that are not deemed BES
transmission and therefore would not require the registration of the GO as
a TO, Manitoba Hydro disagrees with the proposed changes to FAC-001-1 as
Generator Owners may not have the models or expertise to perform
interconnection studies to determine if there is an impact on the
Transmission Network. This concern is echoed in the technical justification
document provided by NERC: ‘the SDT acknowledges that the Generator
Owner may not, at the time it agrees or is compelled to allow a third part to
interconnect, have the necessary expertise to conduct the required
interconnect studies to meet this standard... the Generator Owner will have
to acquire such expertise. How the Generator Owner chooses to do so is
not for the SDT to determine.’ Although it may not be for the SDT to
determine how a GO obtains technical expertise, ensuring that such
expertise is acquired before a GO conducts the required interconnection
studies should be a concern to NERC as this directly affects the reliability of
the BES. As a result, all interconnection requests should be implemented by
the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User
facility as the TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If the scope
of FAC-001-1 also applies to GO owned BES transmission facilities, Manitoba
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
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Organization
Yes or No
Question 1 Comment
Hydro strongly believes that the Compliance Registry should apply and the
GOs should be required to register as a TO and abide by all applicable
standards to that functional type. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected
TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is
maintained. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively
rare.
3) If the redline changes are implemented, GOs are removed from R4,
thereby removing the obligation for GOs to maintain their connection
requirements. If GOs are included in FAC-001, they should be held
accountable to the same level as TOs and should be required to maintain
their connection requirements. Requiring a GO to maintain connection
requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would
initially be inexperienced in performing interconnection studies and would
benefit from regular and frequent review of their connection requirements
as experience and expertise are gained.
4) The revision to FAC-001-1 R2 may be problematic, depending on what
was intended. Under the revised requirement, the obligation to comply is
dependent on the execution of an agreement to evaluate reliability impacts
under FAC-002-1. However, FAC-002-1 does not clearly require the
execution of an agreement by the Generator Owner. FAC-002-1 only
requires the Generator Owner to “coordinate and cooperate on its
assessments with its Transmission Planner and Planning Authority”.
Accordingly if a Generator Owner coordinates without executing an
agreement to perform an assessment, compliance with FAC-001 R1 will not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
be required.
5) Manitoba Hydro would also like to point out that if the redline changes
are implemented, it will greatly increase the complexity of coordination
required under FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP).
The intent of the modifications to this standard is to address the requirements of the GO prior to the interconnection of the third
party to their Facilities. The reliability gap the SDT intends to close is the need for the GO to develop Facility connection
requirements prior to interconnection. The SDT does agree that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
The SDT also refers the commenter to the document titledProject 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document, which is posted on the project page. Specifically, see the last paragraph on page 4 and first two
on page 5.
Tennessee Valley Authority
No
Suggest that the overall structure of the standard be revised such that R1 R3 are applicable to the Transmission Owner (consistent with existing FAC001-0) and R4 (the new requirement) is applicable to the “applicable
Generator Owner”. See further comments below. Support the proposed
revisions to R1 and R4, but suggest R4 be returned to R3 (consistent with
existing FAC-001-0).R3 in the balloted standard should be returned to R2
(consistent with existing FAC-001-0) and only be applicable to the
Transmission Owner. R3.1 (or R2.1 if moved back) should be “fixed”, but it
may be beyond this SDT’s charge. The use of “above” in the FAC-001-0
standard, or the proposed reference to “Requirements R1 or R2” in the
proposed standard do not make sense in combination with the colon used
at the end of the requirement. Suggest that R3.1 (or 2.1 if moved back) be
revised as written below and all sub-requirements of R3.1 be elevated
(R3.1.1 becomes R3.2, R3.1.2 becomes R3.3, etc.).”R3.1 Performance
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
requirements and/or planning criteria used to assess system impacts.” R2 in
the balloted standard should become R4 and modified to incorporate the
connection requirements contained in R3 that can more reasonably be
expected of an “applicable Generator Owner”. For instance, an “applicable
Generator Owner” might simply have a connection requirement for a third
party that addresses coordination of system impact studies with the
appropriate Transmission Owner(s), in lieu of R3.1, R3.1.1, and R3.1.2.
Suggest that R2 (or R4 if moved below existing FAC-001-0 requirements) be
revised as written below.”R2 Each applicable Generator Owner that has
agreed to allow a third party Facility owner (Generation Facility,
Transmission Facility, or End-user Facility) to connect to the Transmission
system through use of pre-existing applicable Generator Owner Facilities
shall communicate it’s Facility connection requirements to the third party.
The applicable Generator Owner Facility connection requirements shall
address the following items: R2.1 Coordination of system impact studies
with the Transmission Owner. R2.2 Voltage level and MW and MVAR
capacity or demand at point of connection. R2.3 Breaker duty and surge
protection. R2.4 System protection and coordination R2.5 Metering....” Etc.
Response: Thank you for your comment. We gave the comment due consideration and agree that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the standard.
No change made.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
The intent of the draft language in FAC-001-1 is to provide guidance for
addressing the alleged reliability gap that exists between GO/GOPs that
own/ operate transmission facilities but are not registered as TO/TOPs. The
impact of the revised language will depend on the characterization of the
generator lead after the “third party “ connects to the existing generator
lead. IF the generator lead is owned by the TO utility after the third party
connection : The proposed DRAFT FAC-001 language suggests that within 45
days of a 3rd party having an executed Agreement to evaluate the reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
19
Organization
Yes or No
Question 1 Comment
impact of interconnecting, the existing generator needs to document and
publish facility connection requirements. The proposed language suggests
that a third party can commandeer existing generators leads and
interconnect. A reclassification would be required because “third party”
power would flow through the downstream portions of the existing leads.
This introduces significant challenges for defining ownership / transfer of
installed assets as well as real property, easements, operational jurisdiction,
O&M cost responsibility, etc.
The FERC approved pro-forma Attachment
X Interconnection Agreement clearly states that the project Developer must
meet all Applicable Reliability Standards which means that all
requirements and guidelines of the Applicable Reliability Councils, and the
Transmission District to which the Developer’s Large Generating Facility is
directly interconnected. As an example, to accommodate this NERC
proposal, the FERC approved NYISO pro-forma tariff would need to be
revised to allow this “third party” use. The pro-forma interconnection tariff
also states that the Developer must provide updated project information
prior to the Facilities Study. The Facilities Study might not be made until
several years after the Interconnection Request /Feasibility Study is made
(“executed Agreement to evaluate the reliability impact of interconnecting”
in this proposed draft is akin to the Interconnection Request/Feasibility
Study). Placing the requirement to have the existing Generator Owner
publish reliability requirements for a potential “third party user”, without
the generator having any knowledge of the potential reliability outcomes or
asset transfer / ownership issues is not a reasonable expectation. The
interconnection of a third party to an existing generator lead would force
existing generators to revise their Interconnection Agreements with FERC.
The “third party”, would at a minimum, need to comply with the existing
Generators reliability obligations as specified in the Interconnection
Agreement.IF the third party connects to the GO owned generator lead, the
GO will be considered a TO:A TO would not be involved, other than review
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
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Organization
Yes or No
Question 1 Comment
of the SRIS and Facilities reports. The difficult thing for an existing GO
would be to prepare, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility, a document listing the requirements.
To allow for the above possibilities, the language for applicability of FAC001 to GO’s or GOP’s, should be :”Each applicable Generator Owner shall, at
least 60 days prior to execution of a Facilities / Class Year Study Agreement
to evaluate the reliability impact of interconnecting a third party Facility to
the Generator Owner’s existing Facility that is used to interconnect to the
Transmission System, document and publish its Facility connection
requirements to ensure compliance with NERC Reliability Standards and
applicable Regional Entity, sub regional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection
requirements.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Consolidated Edison Co. of NY, Inc.
No
The language for FAC-001 Requirement R2 should be:”This requirement
shall apply to each applicable Generator Owner. Generator Owner filings
must be made at least 60 days in advance of execution of the final
interconnection study agreement in the Planning Coordinator’s or
Transmission Planner’s study process.Each applicable Generation Owner
must publish its Facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Entity, sub regional,
Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.The evaluation of the reliability impact(s) of
interconnecting a third party Facility to the Generator Owner’s existing
Facility utilized for interconnection to the Transmission System must be
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
21
Organization
Yes or No
Question 1 Comment
documented.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Unfortunately, the vital point of this requirement revolves around whether
or not a Generator Owner is compelled externally to allow access to their
interconnection facilities. If the GO is driving the connection for financial or
other business reasons, there is no reason they should not be responsible
for developing AND maintaining a facility connection requirements
document. Otherwise, when the local transmission system requirements
change for any reason, there will be no entity responsible to ensure that the
third party will conform as well.Conversely, if the GO should be compelled
to allow access to a third party, it is the responsibility of the “compeller” to
handle all the related reliability studies and documents. This may include
the development of a CFR which separates reliability tasks between the GO
and other entities - especially if a TSP registration is required. This ensures
that the Regional Entity, PUC, RTO, or other regulator must budget dollars
and resources directly related to their action - not cause them to be
directed to a GO.
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. However, the
issues you raise are beyond the scope of the SDT and its SAR. No change made.
PSEG
No
We revised this partial sentence to the following: “Each applicable
Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Transmission Facility that is used for connection
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
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Organization
Yes or No
Question 1 Comment
to the interconnected Transmission systems (under FAC-002-1), ...”- The
phrase “Generator Owner’s existing Facility that is used to interconnect to
the Transmission System” was changed to “Generator Owner’s existing
Transmission Facility that is used for connection to the interconnected
Transmission systems.” - “Transmission” was added before Facility to
exclude connections elsewhere; “Transmission System” was changed to
“Transmission systems” because while “Transmission” and “System” are
defined in the NERC Glossary, “System” means “A combination of
generation, transmission, and distribution components.” “Transmission
systems” do not have generation or distribution components, so a lower
case “system” is warranted. - In addition, the suggested phrase
“interconnected Transmission systems” (plural "systems") uses identical
language from FAC-002-1, except that we capitalized “Transmission.
Response: Thank you for your comment. The SDT has addressed the proposed change to applicability according to your comments.
The applicability section now reads: “Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect to the interconnected
Transmission systems.
The SDT has been informed that in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the
SDT’s attention that in most cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the
GO with FERC. Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain
the term “Transmission.”
Seattle City Light
Affirmative
Key points are that (1) an executed agreement is required before
evaluations of impacts are necessary and (2) this only applies when a third
party is connecting to the generating interconnection line.
Response: Thank you for your comment.
Electric Power Supply Association
Yes
All TO requirements for FAC-001-1 would apply if and when GO executes
an Agreement to evaluate the reliability impact of interconnecting a third
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
23
Organization
Yes or No
Question 1 Comment
party Facility to its existing generation interconnection Facility. The
execution of the agreement is necessary to comply with FAC-002-1 and start
the compliance clock with the applicable regulatory authority. Thus as the
Project 2010-07 Standard Drafting Team (SDT) in its technical justification
has stated, “If, and only if, the existing owner of a generator
interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing
generation Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s
conclusion.The SDT has examined the issue regarding if future requests for
transmission service on the interconnection Facility and in doing so
acknowledged that when that Facility adopted open access and was
providing transmission service it would necessitate re-evaluation of the
need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary
agreement the SDT contemplates in its technical justification of FAC-001-1.
EPSA believes this serves as the necessary trigger for evaluation of
Requirements 2 and 4 under FAC-001-1 for GOs.
Response: Thank you for your comment.
American Wind Energy Association
Yes
AWEA appreciates that this standard specifies that it has limited
applicability. For instance, only those generators that have an executed
agreement with a third party wishing to interconnect must document and
publish Facility connection requirements. We believe the proposed 45-day
time window is a minimum for GO/GOP owners of generator lead lines to
provide this documentation following execution of such an agreement.
Anything less than 45 days could result in a burdensome and hard to meet
deadline for GO/GOP staff. However, AWEA believes that extending this
time window for publishing Facility connection requirements to 90 days
after an executed agreement would be beneficial. We believe this will allow
the GO/GOP owners of generator leads more time to coordinate with their
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
24
Organization
Yes or No
Question 1 Comment
interconnecting Transmission Providers and will result in more reliable and
coordinated connection requirements for the generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO.
No change made.
SERC OC Standards Review Group
Yes
Please verify within the applicability section (4.2.1) you intended to use the
word “within” rather than some other wording.
Response: Thank you for your comment. The SDT intended it to read “Generator Owner with an executed Agreement to evaluate
the reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect
to the Transmission System.” This change has been made.
RES Americas Development
Yes
RES Americas and AWEA appreciate that this standard specifies that it has
limited applicability. For instance, only those generators that have an
executed agreement with a third party wishing to interconnect must
document and publish Facility connection requirements. We believe the
proposed 45-day time window is a minimum for GO/GOP owners of
generator lead lines to provide this documentation following execution of
such an agreement. Anything less than 45 days could result in a
burdensome and hard to meet deadline for GO/GOP staff. However, we
believes that extending this time window for publishing Facility connection
requirements to 90 days after an executed agreement would be beneficial.
We believe this will allow the GO/GOP owners of generator leads more time
to coordinate with their interconnecting Transmission Providers and will
result in more reliable and coordinated connection requirements for the
generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
25
Organization
Yes or No
Question 1 Comment
Yes
We largely agree with the changes the drafting team made but believe
some additional changes are necessary. In section 4.2.1 of the Applicability
Section, “within” should be “with”. Because NERC’s Glossary of Terms
establishes that an Agreement can be verbal and not enforceable by law,
section 4.2.1 should be further modified to clarify that it is a legally
enforceable and fully executed Agreement. The language in R3 in
parenthesis after Generation Owner should be modified to “once required
by Requirement R2”. This makes it clearer that R3 does not apply until the
GO has an executed Agreement to evaluate a request by a third part to
interconnect.
No change made.
ACES Power Marketing Standards
Collaborators
Response: Thank you for your comment. We agree that “within” should be “with”. The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Southwest Power Pool Regional
Entity
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
American Electric Power
Yes
BP Wind Energy North America Inc.
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery Company LLC
Yes
Ameren
Yes
American Transmission Company
Yes
South Carolina Electric and Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 1 Comment
ReliabiltiyFirst
Entergy Services
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
27
Organization
Yes or No
Question 1 Comment
Western Electricity Coordinating
Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power Administration
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
28
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan for FAC-001-1?
Summary Consideration:
The vast majority of commenters supported the one year compliance time frame in the Implementation Plan. A few
commenters were concerned with this time frame and associated enforcement, in part based on similar issues addressed
in recent CANs. The SDT did its best to clarify its intent as follows:
The SDT’s intent is that the mandatory date (the date upon which the GO must be compliant with applicable
requirements and measures) be the first calendar day of the first calendar quarter one year after FAC-001-1’s approval.
The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the
mandatory date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those
requirements shall address items under R3.
No changes were made to the Implementation Plan.
Organization
Yes or No
Ingleside Cogeneration LP
(Occidental Chemical)
No
Question 2 Comment
Based upon similar issues addressed in Compliance Application Notices (CANs),
the drafting team needs to specify how the requirements apply to an in-place
“executed Agreement to evaluate the reliability impact of interconnecting a
third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System.” In the view of Ingleside
Cogeneration LP, if the Agreement takes effect even one day before FAC-001-1
does, requirements R2 and R3 do not apply. Without this clarification, it is
possible that NERC’s Compliance team will apply the requirements retroactively
- with minimum industry input.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
29
Organization
Yes or No
Question 2 Comment
address items under R3.
Southwest Power Pool
Regional Entity
No
No action is required unless a GO has an executed third-party agreement. If a
GO has an agreement, the standard already includes a 45-day timeframe for the
GO to document and publish its facility connection requirements.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
Southern Company
No
See our response to Question 9.
Response: See the SDT’s response to Question 9.
Manitoba Hydro
No
See question 1 comments.
Response: See SDT’s response to Question 1.
Cowlitz County PUD
Yes
Cowlitz PUD (District) registered as a Transmission Owner shortly before FAC001-0 became effective and was forced to file a Mitigation Plan in order to
facilitate compliance. The District successfully completed compliance
implementation and documentation in eight months. The proposed one year
compliance timeframe is sufficient.
Response: Thank you for your comment and support.
Seattle City Light
Yes
The proposed changes for FAC-001-1 state a 45 day period to complete the
evaluation. Not sure what the question is referring to regarding “ 1 year “?
Consideration of Comments: Generator Requirements at the Transmission Interface
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30
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
American Wind Energy
Association / RES Americas
Development
Yes
Yes, since there is no exigent reason why this standard needs to be put in place
at once, we support the one-year compliance timeframe. We believe that it will
allow generators a reasonable time to comply with the requirement.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
31
Organization
Yes or No
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
PSEG
Yes
American Transmission
Company
Yes
Question 2 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
32
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Constellation Power Source
Generation
Yes
Question 2 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
Entergy Services
ReliabiltiyFirst
Texas Reliability Entity
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
33
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the switchyard,
generating station, or generating substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the fenced area of
the generating station switchyard…” We believe that the one mile length is a reasonable approximation of line of sight, and that
using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion on
the part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this qualifier for Generator
Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are
not necessary to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will be made as
Project 2007-07—Vegetation Management moves forward, do you support the proposed redline changes to FAC-003-X and FAC003-3?
Summary Consideration:
The SDT thanks all stakeholders for their comments and their over 85% approval for the FAC-003-X and FAC-003-3
changes posted for ballot in November 2011. Based on stakeholder feedback, the SDT has made the following changes:
-Added a clarifying reference to line of sight in the GO exemption in section 4.3.1.
-Corrected a typo in 4.3.1.2 of FAC-003-3.
-Changed “RE” to “Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally
supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability
benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines
that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have
a clear line of sight from the switchyard fence to the point of interconnection and are…”
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
34
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has been agreed
upon by the stakeholder body. In its Consideration of Comments report from the last formal comment period, which
ended on July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable approximation of line of
sight, and that using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion
and any discretion on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight
reference here, the SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Some stakeholders suggested changes that should have been submitted when Project 2007-07 was revising FAC-003-2,
because these suggestions dealt with the standard as a whole rather than the changes made by this SDT to ensure that
GOs are included in the standard’s applicability.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 3 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of
said line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other
lines. If the GO is only responsible for 0.2 miles, what is the technical basis to ignore
a mile? And would it be the first mile from the switchyard that is ignored, or is the
middle mile, or the last mile where it connects to the TO? Or could the GO decide?
Or could the GO pick sections of the line that amount to a mile that they can ignore?
This seems like something that should be addressed for compliance.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
35
Organization
Yes or No
Question 3 Comment
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT chose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
Wisconsin Public Service Corp
Electric Cooperative
Negative
R1.2 refers to an encroachment due to a fall in. This is confusing because according
to the dictionary “Webster’s II” encroachment reads: “to intrude gradually”, and a
‘fall in’ is not usually gradual.
Response: Thank you for your comment. This is outside the scope of the SAR. The SDT reviewed comments submitted as part of the
Project 2007-07 effort and did not find this comment had been submitted.
Wisconsin Public Service Corp.
Negative
The concern with the proposed wording is that many generating station may not
have a “generating station switchyard” as implied by the proposed wording. Often
the generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers the
now greater than 200 kV lines will be routed to the point of interconnect or a
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
36
Organization
Yes or No
Question 3 Comment
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: A two
kilometer distance from the controlled area perimeter.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Florida Reliability
Negative
There is no technical justification for excluding 1 mile beyond the fence in the
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
37
Organization
Yes or No
Coordinating Council
Question 3 Comment
applicability of generators.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Southern Company
No
 All of these comments pertain to FAC-003-3:
1) We suggest referring to the Implementation Plan in the Effective Date sub-section
of Section A of the standard rather than repeating the content of the
Implementation Plan in the standard. There exists unnessary duplication with
including the information in both places.
2) We suggest simplifying the purpose statement to more succinctly say the intent,
for example: "To maintain a reliable transmission system by managing vegetation
located on transmission rights of way to minimize vegetation encorachments and
thereby minimize the risk of vegetation related outages". If this change is not
acceptable, at least change the phrase "preventing the risk" to "minimizing the risk".
3) We feel that the Enforcement paragraphs between 4.3.1.3 and 5.0 seem to be
out of place. Those paragraphs don’t belong in this location - consider moving them
to Section C. Compliance. The fourth paragraph belongs in the background section.
4) We suggest moving the background section to Section F. "Associated
Documents". It gets in the way of getting to the requirements of the standard.
5) We suggest moving Table 2 of the "Guideline and Technical Basis" document into
R1, since it seems to be the only part of the document that is enforceable. Further
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
38
Organization
Yes or No
Question 3 Comment
we suggest that the Guideline and Technical Basis document be removed from the
standard. The inclusion of this document in the standard makes the standard
unweildy.
6) We suggest reordering the words in R1 to more clearly state the requirement.
Please consider this rephrasing: "For lines which are either an element of an IROL or
an element of a Major WECC Transfer Path, each applicable TO and applicable GO
shall manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) when operating within their Rating during all Rated Electrical Operating
Conditions of the types shown below:..." (remainder is unchanged).
7) We suggest reordering the words of R2 to more clearly state the requirement.
Please consider the this rephrasing: "For lines which are neither an element of an
IROL nor an element of a Major WECC Transfer Path, each applicable TO and
applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within its Rating and during all Rated Electrical
Operating Conditions of the types listed below:..." (remainder is unchanged).
8) On Page 11 of the posted clean draft standard, is the reference to the previous
footnote 2 correct? We recommend eliminating footnotes where possible to
minimize redirections.
9) The Rationale text-box on page 13 of the clean version of FAC-003-3 overlaps
some of the text of footnote #6.    
Response: Thank you for your comment.
With respect to your suggestion regarding the implementation plan, the SDT simply followed the NERC-mandated document
guidelines. Making the change you suggest would deviate from that process and thus the SDT has not made it.
With respect to comments 2-8, any standard changes that go beyond making a standard applicable to a GO or GOP are beyond the
scope of this SDT. Any redline changes the SDT has made within standards were made to clarify or qualify the GO or GOP
applicability. These comments would have been more appropriate to make during the comment period for Project 2007-07
Vegetation Management, the project that revised the version of FAC-003 from which this SDT is working.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
39
Organization
Yes or No
Question 3 Comment
We have modified the rationale box on page 13 so that it does not overlap with the text of footnote 6.
Dominion
No
Dominion suggests in FAC-003-X; 4.3.1. Regional Entity be changed to RE as listed in
4.2.1 for consistency. Also Regional Entity is used throughout the rest of the
document, suggest using RE for consistency overall. Dominion suggests in FAC-003-3;
4.3.1. adding station to the following “ Overhead transmission lines that extend
greater than one mile or 1.609 kilometers beyond the fenced area of the generation
station switchyard and are” to show consistency as it is written in FAC-003-X
4.3.1.Further, Dominion is concerned that the technical justification characterized
the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard) as “approximate line of sign [sic] from a fixed point”
and notes that this line of sight may be limited by local terrain. Where line of sight of
the radial corridor is limited on a clear day due to terrain, the one mile exemption
must be limited in distance to no more than the line of sight on a clear day beyond
the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
Exelon
No
FAC-003 - Exelon supports the one mile length qualifier, but feels that additional
clarification is needed to determine the points of demarcation. There are too many
differing physical configurations to use a “fence line” as a determination of
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
40
Organization
Yes or No
Question 3 Comment
applicability. Suggest that the tie line length be defined as “from the Generator Step
up Transformer GSU to the point of interconnection between the GO and TO owned
equipment.” Also suggest that the standard define what constitutes a generation
station switchyard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
Ingleside Cogeneration LP
(Occidental Chemical)
No
Ingleside Cogeneration LP is very concerned that the attempt to develop “brightline” criteria to assign applicability to either version of FAC-003 is misplaced. As seen
with NERC’s recent proposed directive related to Generator-Transmission
interconnections, those thresholds can be arbitrarily reduced based upon regulators
aversion to risk - not scientific evidence. (As it stands today, NERC has proposed any
interconnection facility operating at 100 kV or higher and greater than 3 spans in
length be applicable - which is even stricter than the TO thresholds in FAC-003.)This
would suggest that a reliability assessment consistent with the TPL standards must
be the determining factor. If the Planning Coordinator or Transmission Planner can
show that the Generator-Transmission interconnection could contribute to a
violation of an SOL or IROL, then a vegetation management program may be in
order.Furthermore, there needs to be some level of common sense applied if a GOTO interconnection is located in an area where vegetation clearance is never an
issue. A one-size-fits-all requirement based upon vegetation growth in the subtropics, should not automatically apply in the desert. In our view, every dollar spent
to control vegetation in an arid climate is one less dollar available to purchase
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
41
Organization
Yes or No
Question 3 Comment
advanced telemetry, AGC systems, and other items which have a far greater impact
on reliability.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
The SDT also took into consideration the stakeholder comments submitted and believes this exemption adequately addresses the
reliability impact for a majority of the Facilities, while balancing the efforts necessary to support the standard from all entities.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in this project. If a
Generator Owner is required to register as a TO, all the Requirements applicable to a
TO should apply. There is no need to change specific Reliability Standards to allow
the Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT also
refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface Background
Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
Suggest in FAC-003-X; 4.3.1. that Regional Entity be changed to RE as listed in 4.2.1
for consistency. Also Regional Entity is used throughout the rest of the document,
suggest using RE for consistency.In FAC-003-3; 4.3.1. add station to the following: “
Overhead transmission lines that extend greater than one mile or 1.609 kilometers
beyond the fenced area of the generation station switchyard and are” to show
consistency as it is written in FAC-003-X 4.3.1.The technical justification
characterized the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
42
Organization
Yes or No
Question 3 Comment
area of the generating station switchyard) as “approximate line of sight [sic] from a
fixed point” and noted that this line of sight may be limited by local terrain. Where
line of sight of the radial corridor is limited on a clear day due to terrain, the one mile
exemption must be limited in distance to no more than the line of sight on a clear
day beyond the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
MRO NSRF
No
The NSRF agrees with the drafting committees desire to eliminate arbitrary and
capricious behavior of auditors and industry staff by precisely defining the point at
which measurement starts for the length of transmission line. The concern the NSRF
has with the proposed wording is that many generating station may not have a
“generating station switchyard” as implied by the proposed wording. Often the
generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers
the now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
43
Organization
Yes or No
Question 3 Comment
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: NSRF
recommends a two kilometer distance from the controlled area perimeter. Our
assessment is that an individual of average height would have a line of site of
approximately 4 Kilometers. Therefore, we recommended a distance of 2 kilometers
from the Controlled Area of the plant to provide margin. The revised applicability
statement would read as follows: “Generator Owner that owns an overhead
transmission line(s) that extends greater than 2.0 kilometers beyond the Controlled
Area of the generating station up to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in
the region. Furthermore we applaud the committee for using the metric system to
identify the acceptable distance for this standard and urge it to remove all
references to English units. We strongly suggest this drafting team and all future
drafting team abandon the anachronistic English measurement system. This archaic
system, based on the length of an average barley corn, should be abandon in all
scientific and engineering endeavors.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
Consideration of Comments: Generator Requirements at the Transmission Interface
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44
Organization
Yes or No
Question 3 Comment
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
Southwest Power Pool
Standards Development Team
No
There is a possibility of some conflict with the Bulk Electric System Definition. This
should be consistent with the Transmission Owner requirements if the lead is
determined part of the BES.
Response: Thank you for your comment. The SDT intended this standard to be applied to Facilities of GO and TO equally, with the
exception of the distance exemption for a generator interconnection Facility. The SDT also notes that FAC-003-2 (approved by the
NERC’s Board of Trustees on Nov. 3, 2011) does not rely upon the BES definition to determine the facility to which this standard
applies (200 kV or higher, or IROL or WECC Transfer Path).
South Carolina Electric and
Gas
No
There should be no qualifying exemption to FAC-003 for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
SERC Planning Standards
Subcommittee
No
We believe there should be no exemption for Generator Owners.
Consideration of Comments: Generator Requirements at the Transmission Interface
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45
Organization
Yes or No
Question 3 Comment
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
PSEG
No
Infigen Energy US
Affirmative
Infigen finds the DST supporting details regarding FAC-003-X to be appropriate. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
Seattle City Light
Affirmative
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
RES Americas Development /
American Wind Energy
Association
Yes
Applying the vegetation management requirements to only generator lead lines that
extend more than “one mile beyond the fenced area of the generating station
switchyard” strikes a reasonable balance among the many stakeholder positions
expressed on this topic. We think that as this criterion recognizes that there is little
need for a vegetation management plan for shorter lines, it should explicitly state
that this is true for all such facilities with lines of that length or smaller.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Texas Reliability Entity
Yes
Question 3 Comment
In the description of the “second effective date” in FAC-003-X there is an erroneous
reference to “Requirement R3,” which should be corrected to “Requirement R1.”
Response: Thank you for your comment and support. This conforming change was made.
Seattle City Light
Yes
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
ACES Power Marketing
Standards Collaborators
Yes
We support the changes to FAC-003 suggested by the drafting team because we
believe the drafting team has provided the best solution in face of a difficult
problem. However, in general, we do not support registration of GOs and GOPs as
TOs and TOPs or applicability of any TO/TOP requirements to the GO/GOP simply
because they have a radial interconnection greater than one mile in length. While
there may be some generators that own interconnecting facilities of significant
length operated at a significant voltage that could impact BES reliability, we do not
believe that the number of generating facilities that fit into that category is
significantly large. When one considers that the majority of generators are still
owned and operator by utilities that are also registered as a TO and TOP, there is
only a minority subset of generators left that could be considered. NERC has the
registration for this remaining set of generators and could use the data to evaluate
how many of this remaining subset have interconnections owned by the generator
that are substantial enough to affect reliability. It seems that NERC could determine
the boundaries of this problem before registering anymore GOs and GOPs as TOs and
TOPs or before applying additional requirements through this effort on the GOs and
GOPs.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
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47
Organization
Yes or No
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Regional Entity
Yes
Florida Municipal Power
Agency
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Question 3 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
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48
Organization
Yes or No
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 3 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of
NY, Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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49
4.
Do you support compliance timeframe for Generator Owners as included and explained in the Implementation Plans for
FAC-003-X?
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-X.
One commenter found a typo in the effective dates section of FAC-003-X, where one section referenced R3 when it
should have referenced R1. That has been corrected in both the standard and the Implementation Plan.
A few stakeholders thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Beyond the corrected typo, no changes were made.
Organization
Yes or No
Ameren Services
Negative
Question 4 Comment
The 2 year compliance time line is far too long. There is significant industry evidence
that was developed in the drafting of Version 2 that supports a one year compliance
time-line for new lines. This is evidenced in Version 2. Thus there is no basis for the 2
years.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Texas Reliability Entity
No
A compliance timeframe for the applicable GOs of two years is too long and the
scenario used as a basis provides no timing specifics or details. Moreover, the 12
months for an existing transmission line operated at 200kV or higher which is newly
acquired by an asset owner and which was not previously subject to this standard is
arguably the same situation as an applicable GO but the applicable GO has an
additional 12 months to come into compliance.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so. The SDT does not believe
that a TO’s acquisition of a new asset is the same as applying new requirements to a GO.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the
drafting team needs to specify when the first vegetation management inspection
quarterly report, and any other requirement with an assigned interval in FAC-003-3 or
FAC-003-X. Even if the decision is to adopt the same criteria proposed in CAN-0012,
the industry is better served with a clear distinction made up front.
Response: Thank you for your comment. This is a comment that is outside the scope of the SDT, and in fact deals with a larger body of
standards than just FAC-003. No change made.
PSEG
No
It’s no longer applicable.
Response: Thank you for your comment. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
– Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Manitoba Hydro
No
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southwest Power Pool
Standards Development Team
No
The effective dates should be consistent with the original standard. If there is a
reason for the extension we would like to know why.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Southern Company
Yes
The development of a working TVMP will take some time to initialize. The 1 year time
frame for R3 is appropriate. The 2 year time frame for all other requirements is
appropriate.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
Seattle City Light
Yes
The explanation deals with the fact that there are simultaneous revisions of FAC-003
underway by two different teams.
Response: Thank you for your comment and support.
MRO NSRF
Yes
There may be a typographical error on the effective date. As currently drafted the
standard states: In those jurisdictions where regulatory approval is required,
Requirement R1 applied to the Generator Owner becomes effective on the first
calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities where such explicit
approval for all requirements is required. In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption. Should it be worded
as follows? In those jurisdictions where regulatory approval is required, Requirement
R1 applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
Response: Thank you for your comment. The SDT agrees with you. “Requirement R3,” will be corrected to “Requirement R1.”
RES Americas Development/
American Wind Energy
Association
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this
standard needs to be put in place at once, we support the proposed compliance
timeframe. We believe that it will allow generators a reasonable time to comply with
the requirement.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
America Inc.
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Western Electricity
Coordinating Council
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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56
5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of different scenarios that could play out
with respect to the filing and approvals of FAC-003-2 and FAC-003-3. Do you support this approach? If there are other scenarios
that the SDT needs to account for, please suggest them here.
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-3.
One commenter thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Some stakeholders expressed confusion about the relationship between FAC-003-3 and the recently BOT-approved FAC003-2. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission
Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff
will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for
both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERCapproved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X
through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
All stakeholders should note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but
stakeholders should not vote as though they are choosing one or the other. As stated above, the SDT plans to present
FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X ready to submit to the Board if, for some
reason, neither FAC-003-2 nor FAC-003-3 are approved by FERC. Members of the ballot body should vote on the merits of
each version of FAC-003 individually. In other words, stakeholders who support adding GOs to the applicability of FAC003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Manitoba Hydro
No
Question 5 Comment
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southern Company
No
We believe that a standard development process should not have parallel paths where
the same version is being modified by multiple teams. The uncertainty in which
development path leads to confusion in the industry and ultimately proves to have
wasted come resources for the path that does not come to fruition.
Response: Thank you for your comment. While the SDT agrees this is not preferable, it was necessary given the urgency of both
projects. The SDT did the best it could to describe the scenarios and reasons for posting multiple versions.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation Management (developed under Project
2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities.
The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and
FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has
elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be
ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration agrees that the SDT’s approach is thorough. We are far more
concerned about FAC-003’s applicability criteria and implementation time frame at
this point - as stated in our responses to questions 3 and 4.
Response: Thank you for your comment and support. Please refer to the SDT’s responses to Questions 3 and 4.
ACES Power Marketing
Standards Collaborators
Yes
With recent NERC BOT approval of the FAC-003-2 standard, the drafting team should
continue to monitor the standard progress with FERC and make necessary
adjustments to the implementation plan.
Response: Thank you for your comment. The SDT acknowledges that FAC-003-2 was recently approved by the BOT. The SDT does not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
see the need to revise the GO implementation plan, as it already accounts for a number of scenarios that could occur based on how
FERC handles the filing of FAC-003-2.
Ameren
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of said
line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other lines.
If the GO is only responsible for 0.2 miles, what is the technical basis to ignore a mile?
And would it be the first mile from the switchyard that is ignored, or is the middle
mile, or the last mile where it connects to the TO? Or could the GO decide? Or could
the GO pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
Consideration of Comments: Generator Requirements at the Transmission Interface
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59
Organization
Yes or No
Question 5 Comment
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT choose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
PSEG
Yes
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
American Wind Energy
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
RES Americas Development
Yes
Sempra Generation
Yes
Entergy Services
Yes
Question 5 Comment
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61
Organization
Yes or No
Xcel Energy
Yes
Cowlitz County PUD
Yes
Texas Reliability Entity
Yes
Constellation Power Source
Generation
Yes
Tennessee Valley Authority
Yes
Question 5 Comment
Southwest Power Pool
Regional Entity
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Consideration of Comments: Generator Requirements at the Transmission Interface
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6. In its technical justification document, the SDT reviews all standards that had been proposed for substantive modification in the
Ad Hoc Group’s original support and explains why, with the exception of FAC-003, modifying them would not provide any
reliability benefit. Do you support these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Summary Consideration:
The SDT thanks all stakeholders for their comments.
A few commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit reference to a
generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing revisions to PRC-005-1a and
will post them soon.
Many commenters encouraged the SDT to reexamine the standards and requirements that FERC and NERC applied to
GOs and GOPs in their Milford/Cedar Creek order and draft compliance directive regarding generator leads. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider
the content of the proposed directive.
Based on stakeholder comments, the SDT expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft
compliance directive. After another thorough review of these standards, the SDT continues to believe that there are clear
and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 6 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
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Organization
Yes or No
Question 6 Comment
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Texas Reliability Entity
No
Our negative votes on FAC-003 reflect our concern that this project has not
considered all of the applicable standards. Why did the SDT choose to only review the
Ad Hoc Group’s standards when there have been multiple registration appeals in
which FERC and NERC have repeatedly cited specific additional TO/TOP standards that
were determined to be applicable to GO/GOPs? This SDT project would serve a
tremendous value to the ERO and in particular industry if it were to address the
technical aspects of the following FERC ordered applicable standards: PRC-001-1 R2,
R4; PRC-004-1 R1; TOP-004-2 R6; PER-003-1 R1; FAC-003-1 R1, R2; TOP-001-1a R1 and
FAC-004-2 R2. The SDT team should analyze the FERC orders, the applicable
standards indicated, and the circumstances and facts involved, and technically justify
why no reliability gap exists if these standards are not applied to GO interface
facilities. The SDT should include more “technical” information in its technical
justification document. For example, in regards to TOP-004-2 R7, the SDT technical
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Question 6 Comment
justification states that there is no reliability gap because, “. . . because an operator
has a fiduciary obligation to protect a Facility for which it is operationally
responsible.” An entity having a fiduciary obligation is not a technical justification of
why a reliability gap does not exist. Moreover, by that logic there would be no need
for many standards because every registered entity has a fiduciary obligation to
protect its facilities.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
We would like to clarify, in response to the comment concerning TOP-004-2 R7, that in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface” the SDT also stated “FAC-008-1—Facility Ratings
Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for establishing a ratings
methodology and communicating facility ratings to the Reliability Coordinator, Planning Authority, Transmission Planner, and
Transmission Operator is for use in reliable planning and operation of the Bulk Electric System.”
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
PSEG
No
PRC-005-1 - Transmission and Generation Protection System Maintenance and
Testing was recommended by the Ad Hoc Group for modification, but not addressed
to the technical justification document. It should be.
Response: Thank you for your comment. We have reviewed PRC-005-1a and believe that the wording in R1 and R2 of that standard
require the same explicit reference to a generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing
revisions to PRC-005-1a and will post them soon.
Florida Municipal Power
No
see comment to Question 7
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Yes or No
Question 6 Comment
Agency
Response: See the SDT’s response to Question 7.
Manitoba Hydro
No
See Question 7 comments.
Response: See the SDT’s response to Question 7.
MRO NSRF
No
The NSRF has one concern with the current justification and definitions. At some
point, if enough interconnections are made to generator outlet leads in accordance
with FAC-001, the original generator operator will be a Transmission Operator and a
Transmission Owner. This point in time needs to be explicitly defined by the drafting
team.
Response: The SDT cannot act on this comment. Registration is outside the scope of this SDT and resides with NERC and the Regional
Entity.
Manitoba Hydro
If the drafting team intends to limit the scope of FAC-001-1 to GO owned radial
generator interconnection facilities that are not deemed BES transmission and
therefore would not require the registration of the GO as a TO, Manitoba Hydro
disagrees with the proposed changes to FAC-001-1 as Generator Owners may not
have the models or expertise to perform interconnection studies to determine if
there is an impact on the Transmission Network. This concern is echoed in the
technical justification document provided by NERC: ‘the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third part
to interconnect, have the necessary expertise to conduct the required interconnect
studies to meet this standard... the Generator Owner will have to acquire such
expertise. How the Generator Owner chooses to do so is not for the SDT to
determine.’ Although it may not be for the SDT to determine how a GO obtains
technical expertise, ensuring that such expertise is acquired before a GO conducts the
required interconnection studies should be a concern to NERC as this directly affects
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Question 6 Comment
the reliability of the BES. As a result, all interconnection requests should be
implemented by the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User facility as the
TO is in the best position to set unbiased connection requirements to ensure the
reliability of the BES is maintained. If the scope of FAC-001-1 also applies to GO
owned BES transmission facilities, Manitoba Hydro strongly believes that the
Compliance Registry should apply and the GOs should be required to register as a TO
and abide by all applicable standards to that functional type. There is no need to
change specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards, including the
protection standards, are met so the reliability of the BES is maintained. At this time,
this would not lead to a large number of extra registrations since, as stated in the
technical justification document, ‘interconnection requests for Generator Owner
Facilities are still relatively rare.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs. The SDT does agree that upon interconnection of a third party, other standards or registrations
may apply as appropriate.
Electric Power Supply
Association
Affirmative
All TO requirements for FAC-001-1 would apply if and when GO executes an
Agreement to evaluate the reliability impact of interconnecting a third party Facility
to its existing generation interconnection Facility. The execution of the agreement is
necessary to comply with FAC-002-1 and start the compliance clock with the
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Question 6 Comment
applicable regulatory authority. Thus as the Project 2010-07 Standard Drafting Team
(SDT) in its technical justification has stated, “If, and only if, the existing owner of a
generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation
Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s conclusion. The SDT
has examined the issue regarding if future requests for transmission service on the
interconnection Facility and in doing so acknowledged that when that Facility adopted
open access and was providing transmission service it would necessitate re-evaluation
of the need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary agreement
the SDT contemplates in its technical justification of FAC-001-1. EPSA believes this
serves as the necessary trigger for evaluation of Requirements 2 and 4 under FAC001-1 for GOs.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen supports the FAC-001-1 technical analysis by the Project 2010-07 SDT, which
states in part that “If, and only if, the existing owner of a generator interconnection
Facility has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply”. We agree with the SDT’s reasoning that if the owner of
the existing generator interconnection Facility agrees, or is compelled to allow a third
party to interconnect, but can do so using existing agreements, contracts, and/or
tariffs [to avoid requiring additional executed Agreement(s)], this is the most prudent
and effective way to manage this process with continuity. In order to evaluate the
reliability impact of interconnecting a third party Facility to the Generator Owner’s
existing Facility more expediently, it can avoid having to develop its own connection
requirements or perform additional impact studies, to the extent possible. We find it
reasonable to negotiate with the existing Transmission Owner, Transmission Planner,
and/or Transmission Service Provider to manage this requirement, utilizing their
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Question 6 Comment
existing processes and Agreements for the purpose of fulfilling FAC-001-1.
Response: Thank you for your comment and support.
Southern Company
Yes
Additional responses are needed to justify the exclusion of the list of requirements
and standards found in the recent FERC order denying the rehearing request of the
Compliance Registry Appeals of Cedar Creek and Milford. (135 FERC Para. 61,241).
Please see our response to Question 10 for a detailed discussion on this
topic.   
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
Constellation Power Source
Generation
Yes
Constellation supports the SDT justifications and offers additional information in our
response to question 10.
Response: Thank you for your comment and support.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration LP believes the SDT has spent a significant amount of time and
effort to demonstrate that only FAC-001, FAC-003, and PRC-004 need to be modified
to address any reliability gaps that may exist related to the GO-TO interconnection.
We agree that the other standards/requirements identified by the Ad Hoc Group are
covered elsewhere.
Response: Thank you for your comment and support.
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Organization
Yes or No
American Wind Energy
Association
Yes
Question 6 Comment
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
RES Americas Development
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
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Organization
Yes or No
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Yes
Question 6 Comment
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Organization
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Question 6 Comment
Gas
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Independent Electricity
System Operator
Ameren
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
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Question 6 Comment
Tennessee Valley Authority
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7. The SDT is attempting to modify a set of standards so that radial generator interconnection Facilities are appropriately accounted
for in NERC’s Reliability Standards, both to close reliability gaps and to prevent the unnecessary registration of GOs and GOPs at
TOs and TOPs. Does the set of standards currently posted achieve this goal?
Summary Consideration:
The SDT thanks all stakeholders for their comments. Most commenters support the SDT’s work and agree that the set of
standards for which the SDT has proposed modification ensure that radial generator interconnection Facilities are
appropriately accounted for in NERC’s Reliability Standards.
One commenter continues to express confusion about the scope of the SDT’s work in general. The SDT reminded this
commenter that its scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with
ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it
should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
transmission entity (TO/TOP). Through its deliberations, the SDT came to the conclusion that an interconnection Facility
owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT. The SDT also refers the commenter to the document titled Project
2010-07: Generator Requirements at the Transmission Interface Background Resource Document (specifically, the last
paragraph on page 4 and first two on page 5). The SDT has proposed the modification of a select set of standards so that
they apply to GOs and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been
widely supported by the stakeholder body. The SDT does agree that upon interconnection of a third party, other
standards or registrations may apply as appropriate.
One commenter asked the SDT to specify what it means by “radial.” By “radial generator interconnection Facilities,” the
SDT means sole-use Facilities (see posted examples under “Supporting Materials”) – that is, a Facility used to connect one
or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
A few commenters suggested that the SDT address those standards cited by FERC and NERC in related projects. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process. However, based on staekolder
comments, the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include
any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
After another thorough review of these standards, the SDT continues to believe that there are clear and technical
reliability-based reasons that support not adding GO and GOP requirements to these standards.
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One commenter suggested that the SDT include the GO in TOP-004-2 R6, but the SDT continues to maintain that no gap
exists because TOP-002-2 R3 already requires the GO to coordinate with its host BA and TSP, who in turn are required to
coordinate with their TOPs.
One commenter pointed out that the Data Retention section of the proposed PRC-004-2.1a also requires modification to
include the generator interconnection Facility. The SDT agrees and made this change.
Organization
Yes or No
Manitoba Hydro
Negative
Question 7 Comment
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
2) Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry
and only having a limited set of standards apply to the GOs ‘interconnection facilities’
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
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Question 7 Comment
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Manitoba Hydro
Negative
Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry and
only having a limited set of standards apply to the GOs ‘interconnection facilities’ If a
Generator Owner wants to own transmission facilities and it falls under the definition
of a Transmission Owner under the NERC Registry Criteria, then all the Requirements
applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions.
Reliability gaps would be better closed if select GOs and GOPs simply registered as
TOs and TOPs. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document, ‘interconnection
requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The SDT has proposed the modification of a select set of standards so that they apply to GOs
and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the
stakeholder body. The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as
appropriate.
PSEG
No
It would be helpful if the SDT defined what it means by the term “radial generator
interconnection Facilities.” Does it mean interconnection Facilities that under Normal
Clearing for a fault do not interrupt flows on other BES Elements? This is also
confusing because of the radial exclusion included in the BES definition work in
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Question 7 Comment
Project 2010-17. That definition would allow part of a three-terminal circuit to be
excluded from the BES, while the other parts are included in the BES.
Response: Thank you for your comment. By “radial generator interconnection Facilities,” the SDT means sole-use Facilities (see posted
examples under “Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated
by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that a interconnection Facility owned or
operated by a GO/GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside
the scope of this SDT.
Texas Reliability Entity
No
See comment 6.
Response: See the SDT’s response to Question 6.
Manitoba Hydro
No
The SDT’s proposed modifications gives special treatment to the Generator Owner in
that it allows the Generator Owner TO status for a couple of standards (FAC-001, FAC003 and PRC-004), but exempts the Generator Owner from many of the standards
applicable to a TO. The NERC Registry Criteria defines the various functional entities.
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
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Question 7 Comment
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Southwest Power Pool
Regional Entity
No
The Technical Justification document did not review the standards FERC identified in
paragraphs 71 and 87 of 135 FERC ¶ 61,241 ORDER DENYING APPEALS OF ELECTRIC
RELIABILITY ORGANIZATION REGISTRATION DETERMINATIONS. The SDT needs to
review these standards to determine if changes are needed; otherwise, FERC will
require registration of GOs and GOPs as TOs and TOPs to address reliability gaps. If
the SDT determines no changes are needed to these FERC-identified standards, they
should provide justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives) within the standards process. However, based on your and other comments, we have
expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards,
the SDT continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP
requirements to these standards.
Southern Company
No
We don’t believe the effort realizes the goal because 1) it is inclusive of FAC-001 that
does not need any modifications and 2) the effort needs to reinforce the appropriate
justification not to include the additional standards FERC has identified in their Cedar
Creek and Milford Orders.
Response: The SDT thanks you for your comment. The SDT believes that comment (1) is a complex issue and did its best to outline
how it arrived at its position in the document titled “Technical Justification: FAC-001-1.”
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Question 7 Comment
As for comment (2), the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that don’t
include explicit directives) within the standards process. However, based on your and other comments, we have expanded our
technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
Western Electricity
Coordinating Council
No
WECC casts an affirmative vote for the SDT proposal as a necessary but not sufficient
step in addressing the GOTO matter. WECC, NERC, and the other Regions developed
a subset of Standards and Requirements that were considered necessary to address
potential gaps for transmission interconnection facilities and operations to be
included in a proposed NERC Directive, which is expected to issue by year-end. The
subset of requirements developed for the proposed NERC Directive were informed by
the applicable FERC Orders. Consequently, it is important that the SDT address the
comparative reliability risks between the proposed NERC Directive List and the SDT
Proposal to assure that reliability gaps will not result from the SDT proposal. Please
see NERC’s proposed Directive for the rationale and technical justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
However, based on your and other comments, we have expanded our technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance
directive. After another thorough review of these standards, the SDT continues to believe that there are clear and technical reliabilitybased reasons that support not adding GO and GOP requirements to these standards.
Florida Municipal Power
Agency
FMPA believes that TOP-004-2 R6.2 ought to also be addressed in the standards as
applicable to GOPs. The requirements reads:R6. Transmission Operators, individually
and jointly with other Transmission Operators, shall develop, maintain, and
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Question 7 Comment
implement formal policies and procedures to provide for transmission reliability.
These policies and procedures shall address the execution and coordination of
activities that impact inter- and intra-Regional reliability, including:R6.2. Switching
transmission elements.Although planned outages are covered in other standards
applicable to a GOP, switching to close / synchronize a generator back to the system is
not specifically covered in the standards. Some have argued that TOP-002-2 R3 causes
GOPs to coordinate its current day plans with the TOP; however, the name of the
standard is “Transmission Operations Planning” and therefore implies the availability
of the generator and related equipment and not necessary implies the policies and
procedures for switching operations; which includes synchronization. FMPA cannot
imagine a generator that would not have such switching / synchronization policies
and procedures coordinated with its interconnecting TOP; as such would normally be
required through a Large Generator Interconnection Agreement through a pro forma
OATT; however, FMPA is not aware of any instance in the standards that covers this.
As such, FMPA recommends including TOP-004-2 R6.2 as being applicable to a GOP.
Response: Thank you for your comment. We don’t agree that the gap exists because TOP-002-2 R3 already requires the GO to
coordinate with its host BA and TSP, who in turn are required to coordinate with their TOPs.
Manitoba Hydro
If the redline changes are implemented, GOs are removed from R4, thereby removing
the obligation for GOs to maintain their connection requirements. If GOs are included
in FAC-001, they should be held accountable to the same level as TOs and should be
required to maintain their connection requirements. Requiring a GO to maintain
connection requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would initially
be inexperienced in performing interconnection studies and would benefit from
regular and frequent review of their connection requirements as experience and
expertise are gained.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
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Question 7 Comment
in the document titled “Technical Justification: FAC-001-1.”
SERC OC Standards Review
Group
Please list the set of standards are you referencing.
Response: The SDT is referring to those standards posted for comment (FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1).
Constellation Power Source
Generation, Inc.
Affirmative
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. Please see more detailed comments submitted in the Project 201007 comment form submitted on November 18, 2011.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen finds the SDT supporting measures and analysis regarding FAC-003-3 to be
appropriate, and believes that it is prudent for Generation Owners and Transmission
Owners to manage vegetation maintenance records/inspections accordingly. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
Affirmative
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
The SDT agrees with your comment regarding the language in the Data Retention section and has modified that section as follows:
“The Transmission Owner, and Distribution Provider that own a transmission Protection System and the Generator Owner that owns a
generation or generator interconnection Protection System…”
Southwest Transmission
Cooperative, Inc. / ACES
Power Marketing
Affirmative
We largely support the changes made by drafting team because we believe the
drafting team has provided the best solution in face of a difficult problem. However,
in general, we do not support registration of GOs and GOPs as TOs and TOPs or
applicability of any TO/TOP requirements to the GO/GOP simply because they have a
radial interconnection greater than one mile in length. While there may be some
generators that own interconnecting facilities of significant length operated at a
significant voltage that could impact BES reliability, we do not believe that the
number of generating facilities that fit into that category is significantly large. When
one considers that the majority of generators are still owned and operator by utilities
that are also registered as a TO and TOP, there is only a minority subset of generators
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left that could be considered. NERC has the registration for this remaining set of
generators and could use the data to evaluate how many of this remaining subset
have interconnections owned by the generator that are substantial enough to affect
reliability. It seems that NERC could determine the boundaries of this problem before
registering anymore GOs and GOPs as TOs and TOPs or before applying additional
requirements through this effort on the GOs and GOPs. Subjecting a GO/GOP to any
TO/TOP standards requirements should require a clear demonstration f the reliability
gap in each instance. Some additional changes are necessary to FAC-001.
Response: Thank you for your comment and support. We are unsure as to what changes to FAC-001 you feel are necessary unless you
are referring to comments stated previously.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Although the SDT is nearing conclusion on the closing of reliability gaps, the
unnecessary registration of GOs and GOPs as TOs and TOPs is far from resolved in our
view. Ingleside Cogeneration’s concern is based upon NERC’s recent proposal to
dictate an interim GO-TO interconnection solution which completely bypasses the
Standards Development Process. Frankly, it seriously brings to question the nature of
the consensus-driven process - which appears to be moving in a dictatorial direction.
Response: Thank you for your comment and support.
American Wind Energy
Association
Yes
AWEA believes that the standards modifications proposed by the SDT should address
any genuine reliability gap with regard to generator lead lines, rather than just
perceived but unsupported threats. To that end, we support the approach that the
SDT appears to be taking of modifying a limited number of applicable standards so
that they apply to GO/GOP lead lines. In particular, we fully support the fact that the
SDT recognizes that GO/GOPs should not automatically be required to register as
TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case
determination. As already noted, registering a GO/GOP as a TO/TOP may actually
decrease reliability.
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Question 7 Comment
Response: Thank you for your comment and support.
RES Americas Development
Yes
We believe that the standards modifications proposed by the SDT should address any
genuine reliability gap with regard to generator lead lines, rather than just perceived
but unsupported threats. To that end, we support the approach that the SDT appears
to be taking of modifying a limited number of applicable standards so that they apply
to GO/GOP lead lines. In particular, we fully support the fact that the SDT recognizes
that GO/GOPs should not automatically be required to register as TO/TOPs simply
because of their ownership of generator lead lines. The SDT correctly recognizes that
such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Response: Thank you for your comment and support.
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Yes
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Question 7 Comment
Standards Collaborators
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Xcel Energy
Yes
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Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 7 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
South Carolina Electric and
Gas
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
Tennessee Valley Authority
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8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the appropriate ones?
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, commenters either offered their support or directed
the SDT to their comments on other questions in this report.
Organization
Yes or No
Ameren
No
Question 8 Comment
Please refre to our comments in reposnes to #3, #4, and #5 above.
Response: Please see the SDT’s responses to Questions 3, 4, and 5.
Texas Reliability Entity
No
See comment 6.
Response: Please see the SDT’s response to Question 6.
Ingleside Cogeneration LP
(Occidental Chemical)
No
See comments to questions 1 through 4.
Response: Please see the SDT’s responses to Questions 1-4.
SERC Planning Standards
Subcommittee
No
See our comments above for question # 3.
Response: Please see the SDT’s response to Question 3.
South Carolina Electric and
Gas
No
The modifications are appropriate with the exception noted in question #3.
Response: Please see the SDT’s response to Question 3.
ACES Power Marketing
No
The modifications are largely the appropriate ones with the exceptions we noted in Q1
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Standards Collaborators
Question 8 Comment
and Q10.
Response: Please see the SDT’s responses to Questions 1 and 10.
Southwest Power Pool
Standards Development Team
No
We agree that the standards being addressed are correct. See above comments.
There are some issues with the determination of which facilities are deemed BES since
ownership of what may be a BES facility may not always be by a Transmission Owner.
All relevant standards should apply to BES facilities regardless of ownership.
Response: Thank you for your comment.
PSEG
No
Response:
SERC OC Standards Review
Group
See comments on Question 7. If the standards referenced in question 7 are FAC-001,
FAC-003 and PRC-004, we would answer yes to this question.
Response: Thank you for your comment and support.
Southern Company
Yes
 The version history table is incorrect - change version 3 to version 2.1.  
Response: Thank you for your comment. We have made this change.
RES Americas Development/
American Wind Energy
Association
Yes
For the most, we agree that the SDT proposal strikes a reasonable balance and
provides the requisite level of clarity and certainty necessary for GO/GOPs to
understand their responsibilities and compliance requirements.
Response: Thank you for your comment and support.
MRO NSRF
Yes
The NSRF agrees if the drafting team incorporates as suggested improvements
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Question 8 Comment
Response: Thank you for your comment and support.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Yes
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Organization
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Question 8 Comment
Company
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
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9. If you answered “no” to Question 7, what standards need to be added or removed to achieve the SDT’s goal? Please provide
technical justification for your answer.
Summary Consideration:
The SDT thanks all stakeholders who submitted comments. Few stakeholders suggested that standards need to be added
or removed to achieve the SDT’s goal.
One commenter pointed out that PRC-005-1a required the same kind of change made in the proposed PRC-004-2.1a to
ensure that generator interconnection Facility Protection Systems are included within that standard. The SDT agrees with
this suggestion and has initiated a process to modify R1 and R2 in PRC-005-1a.
A few commenters returned to FAC-001-1 and stated their concern about the feasibility of adding FAC-001-1 to the
applicability section of this standard. The SDT agrees with commenters that the issues surrounding the interconnection of
a third party Facility to a GO’s existing Facilities are complex ones, and reminded commenters that it did its best to
address these complexities in the resource document titled “Technical Justification: FAC-001-1.” The SDT also points out
that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or indirectly
with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro
forma interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any
studies with an affected system which could include Facilities owned by one, or more, TO on the other side of the GO’s
existing point of interconnection. The SDT acknowledges that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
Some commenters suggested that the SDT reexamine the standards cited in the Milford and Cedar Creek FERC orders.
The SDT continues to find clear and technical reliability-based reasons that support not adding GO and GOP requirements
to these standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern,
the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 9 Comment
Cowlitz County PUD
No
N/A
Manitoba Hydro
No
See question 7 comments.
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Response: See the SDT’s response to Question 7.
Southern Company
Yes
Southern does not think that the revision to FAC-001-1 is necessary. A Generator
Owner (GO) cannot assess reliability impacts to the Bulk Electric System (BES) and
determine acceptability without support and involvement of the applicable owner and
operator of the Transmission System (i.e., the “interconnected TO” or “interconnected
TP”). A generator tie-line does not equate to a Transmission System. A GO must
already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties’ facilities to its own interconnection
Facilities. Stated another way, the GO does not need Facility Connection
requirements to govern how multiple units are tied to a collector bus so why are they
needed for a third party to connect to an existing tie-line? In either case it is the
interconnected TO or interconnected TP that has connection requirements that must
be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its
interconnected TO or interconnected TP. A GO should not need to develop
“connection requirements” unless it is in the business of owning and operating
facilities independently of its interconnected TO or interconnected TP. We do not
believe a reliability gap exists in FAC-001-1 because the requestor for interconnecting
another Facility to an existing generation Facility must coordinate with the applicable
TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable facility
connection and performance requirements. If and when there is an agreement in
place for a third party to connect to a generator tie-line then the tie-line would
become part of the integrated system and its purpose and the owner’s function would
likely warrant registration as a TO/TOP and FAC-001 would then apply. The following
excerpt from the 2010-07 Background Resource White Paper acknowledges that this
may be necessary: “The drafting team also acknowledges that, if another party
interconnects to a Facility owned by a Generator Owner, there may be the need to
address MOD or TPL standards. However, the drafting team believes that this, too, is
best handled through specific evaluation, perhaps accompanied by changes to the
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compliance registry. Entities that face this kind of scenario may also meet criteria
applicable to other registrations such as Transmission Service Provider or Transmission
Planner.” [Arguments related to jurisdictional, interconnection policy and open access
transmission tariff issues](1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access
transmission tariff (OATT), a GO should not be required to comply with FAC-001-1
until that GO’s generating Facility reaches commercial operation. NERC should not
make facilities subject to the mandatory reliability standards before the facilities are
actually part of the BES.(a) Jurisdiction under FPA Section 215. First, it is not clear
that NERC or FERC has jurisdiction under FPA Section 215 to require generation
facilities that have not actually reached commercial operation to be subject to
reliability standards. Section 215(a)(2) of the FPA defines the “Electric Reliability
Organization” as “the organization certified by the Commission ... the purpose of
which is to establish and enforce reliability standards for the bulk-power system,
subject to Commission review.” Further, (a)(3) provides that “The term ‘reliability
standard’ means a requirement, approved by the Commission under this section, to
provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide
for reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design
of planned additions or modifications. It is logical to interpret the phrase “design of
new facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted
as requiring that a generating facility that has not yet reached commercial operation
should be subject to reliability standards (including audit and penalties). Therefore,
the GO with the existing generation facilities should not be required to incorporate
the proposed generation facility into its Facility connection requirements before the
proposed generation facility is subject to NERC or FERC jurisdiction. (b) FERC’s
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interconnection policy. In addition, the revised FAC-001 would appear to place
restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC
was very concerned about the ability of interconnection customers to interconnect
their generating facilities and gave them a fair amount of flexibility. However, this
revised FAC-001 would appear to restrict some of this flexibility.(i) Order No. 2003
gives the interconnection customer the ability to terminate a proposed
interconnection on ninety days notice. Therefore, the interconnection customer is not
required to build the facility. However, this revised FAC-001 appears to assume that
the interconnection customer does not have this flexibility. What if the
interconnection customer (the GO building a new generator on its site or the third
party building a new generation facility) decides to terminate the Large Generator
Interconnection Agreement (LGIA) or not proceed with the generation facility? In such
event, the GO may be required to revert to its previous Facility connection
requirements in order to accommodate the original configuration. (ii) The LGIA
permits modifications to the proposed interconnection. How would this affect the
Facility connection requirements? How long would the GO have to revise its Facility
connection requirements? In the event that there is a single modification, or perhaps
multiple modifications, how does the GO stay in compliance with this standard? (iii)
FAC-001-1, R4 provides that each GO with Facility connection requirements and each
TO shall maintain Facility connection requirements and make documentation of these
requirements available to users of the Transmission System upon request. However,
Large Generator Interconnection Procedures (LGIP), Section 3.4 requires the posting
of certain interconnection information but the identity of the interconnection
customer is not to be disclosed (unless it is an Affiliate). Requirement R4 would
appear to potentially require disclosure of information and (more importantly) of the
interconnection customer's identity in contravention of the requirements in Order No.
2003 and the LGIP.(c) OATT requirements. The definition of “applicable Generator
Owner” (Section 4.2.1) and Requirement R2 provide that the GO will have an executed
Agreement to evaluate the impact of interconnecting a new facility to the GO’s
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existing generation facility. This statement is ambiguous. This statement could be
understood to mean that the GO of the existing generation Facility will enter into an
Agreement with the GO proposing to interconnect and the existing GO will evaluate
the impact of the proposed interconnection. However, requests to interconnect new
generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the
new facility. Thus, the language in FAC-001-1 would need to be revised to clarify that
the owner of the new facility will need to interconnect under the OATT of an
appropriate Transmission Provider (i.e., the Transmission Provider to which the
existing GO is interconnected, not with the existing GO). Therefore, the owner of the
new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be
developing a merchant transmission line. In that case, the existing GO would need to
evaluate whether it needs have its own OATT and OASIS. In that case, the new
generator owner would be interconnecting to the existing GO. However, the existing
GO’s line would not be a generator tie-line. This issue is not clear from the draft
standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES
reliability...” (b) It is unclear in Applicability section 4.2.1 that the term “Agreement”
means that the GO has an executed agreement with a TO/TSP or that the GO and the
third party have an executed agreement. Without further explanation, the capitalized
term “Agreement” has the effect of introducing confusion. If the SDT does not intend
to propose a new addition to the NERC Glossary of Terms, it should use the lower case
term, “agreement.” With respect to the capitalized term, “Transmission System,” the
SDT should consider clarifying if it intends to propose adding this to the Glossary. (3)
Effect of the proposed revisions to FAC-001-1 on FAC-002-1.(a) As drafted, there are
scenarios under which a new GO may attempt to interconnect to an existing GO even
though, as explained above, the interconnection should actually be done to the
appropriate Transmission Provider. If the appropriate Transmission Provider is not
included in the evaluation of the interconnection various types of harm may occur. In
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such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002. (b) FAC-001 and FAC-002 should
be revised to be clear that the existing GO and any new GOs must coordinate any
interconnection with the appropriate Transmission Provider, TP and PA.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as appropriate.
PSEG
Yes
We believe that the Ad Hoc Group’s suggestions regarding PRC-005-1 - Transmission
and Generation Protection System Maintenance were correct and that this standard
should have been modified by the SDT in a manner similar to the way the SDT
modified PRC-004-2. This would require modifying R1 and R2 in PRC-005-1a (the
current version) to include protection systems in the generator interconnection
Facility. In addition, the SDT should evaluate modifying PER-002-0 - Operation
Personnel Training. In doing so the SDT completes one of the open FERC directives in
Order 693. Paragraph 1363 addresses GOP training:1363. Further, the Commission
agrees with MidAmerican, SDG&E and others that the experience and knowledge
required by transmission operators about Bulk-Power System operations goes well
beyond what is needed by generation operators; therefore, training for generator
operators need not be as extensive as that required for transmission operators.
Accordingly, the training requirements developed by the ERO should be tailored in
their scope, content and duration so as to be appropriate to generation operations
personnel and the objective of promoting system reliability. Thus, in addition to
modifying the Reliability Standard to identify generator operators as applicable
entities, we direct the ERO to develop specific Requirements addressing the scope,
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content and duration appropriate for generator operator personnel.
Response: Thank you for your comment. The SDT agrees with the comment concerning PRC-005-1a and will be initiating a process to
make that change.
With respect to PER-002-0, the SDT continues to find that there are no clear and technical reliability reasons that support adding GOP
requirements to any PER standard based on the fact that the GOP operates a generator interconnection Facility. While the SDT does
not necessarily disagree that some training requirements for GOPs may be necessary, it does not see how these changes fall within its
scope.
Ingleside Cogeneration LP
(Occidental Chemical)
Ingleside Cogeneration LP believes that the set of standards proposed by the SDT is
technologically accurate and defensible. The open issue is if the ERO and FERC expect
more standards to be included - whether based upon sound reliability principals or
not.
Response: Thank you for your comment and support.
Western Electricity
Coordinating Council
PLease see response to question #7.
Response: See the SDT’s response to Question 7.
Texas Reliability Entity
See comment 6.
Response: See the SDT’s response to Question 6.
SERC OC Standards Review
Group
See comments on Questions 7 & 8.
Response: See the SDT’s responses to Questions 7 and 8.
Florida Municipal Power
see response to Question 7
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Agency
Response: See the SDT’s response to Questions 7.
Manitoba Hydro
The revision to FAC-001-1 R2 may be problematic, depending on what was intended.
Under the revised requirement, the obligation to comply is dependent on the
execution of an agreement to evaluate reliability impacts under FAC-002-1. However,
FAC-002-1 does not clearly require the execution of an agreement by the Generator
Owner. FAC-002-1 only requires the Generator Owner to “coordinate and cooperate
on its assessments with its Transmission Planner and Planning Authority”. Accordingly
if a Generator Owner coordinates without executing an agreement to perform an
assessment, compliance with FAC-001 R1 will not be required.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Southwest Power Pool
Regional Entity
The SDT should consider the standards that FERC identified in 135 FERC ¶ 61,241.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives). However, based on your and other comments, we have expanded our technical
justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
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10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, many stakeholders offered supportive comments.
Others offered a variety of suggestions, many of which were addressed.
One commenter suggested that the word “system” should not be capitalized in “Transmission System” in FAC-001-1
because the NERC glossary term “System” does not apply within the standard. The SDT agreed with this suggestion, and
changed all references to “Transmission System” to “interconnected Transmission systems” for consistency in other parts
of the standard and with FAC-002. Another commenter pointed out that “within” should be “with” in Section 4.2.1, and
the SDT made this change.
A few commenters repeated their concern with the exclusion in FAC-003 for GOs with specific kinds of interconnection
Facilities. For these commenters, the SDT reemphasized that in many cases, generation Facilities are either (1) staffed and
the overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have
generally supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines
that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have
a clear line of sight from the switchyard fence to the point of interconnection and are…”
Some stakeholders offered comments that were outside the scope of this SDT’s work. A few offered comments on the
overall strategy of the FAC-003-2 standard, and the SDT informed them that these comments should have been
submitted when the Project 2007-7 Vegetation Management posted its work for comment.
One commenter suggested changes to the VSLs for R1 and R4. Because the SDT made no changes to these requirements,
modifying the VSLs for these requirements is outside the scope of this team. This item will be added to the issues
database.
Several stakeholders suggested the SDT review the standards cited in the draft NERC directive regarding generator
interconnection leads and in the FERC orders regarding Milford and Cedar Creek. The SDT continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these standards and not
requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern, the SDT has expanded its
Consideration of Comments: Generator Requirements at the Transmission Interface
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technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 10 Comment
Gainesville Regional Utilities
Negative
1. It would seem that the impetus for FAC003 is to eliminate vegetation related
outages within the rights-of-way as defined and subject to the exclusions as stated in
footnote
2. Thus the requirement is to manage the ROW to prevent vegetation related
sustained outages with the measure being no outages. With grow-ins and fall-ins from
within the defined ROW being controllable factors. 2. Including encroachments leaves
the door open for fines to be imposed with no actual outage(s) having occurred. This
may be like being found guilty of a crime that has not yet taken place.
3. Combine vegetation related sustained outages by “grow-ins” and “blowing
together of lines and vegetation located inside the ROW” as one item as they are both
consequences of the growth of vegetation either vertically and horizontally.
4. Leave vegetation related sustained outages by “fall-in” as a standalone as this will
be related to structural problems occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and implementation of a Transmission
Vegetation Management Plan which shall include documented maintenance
strategies or procedures or processes or specifications, delineation of an annual work
plan and completion of same). Thus this would be the competency based
requirements as a program without execution is meaningless.
6. R1 and R2 become R2 and R3.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and found that a response to this comment was provided. No change made.
Northern Indiana Public
Service Co.
Negative
Ballot needs work
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Question 10 Comment
Response: The SDT does not understand your specific concern.
PSEG Energy Resources &
Trade LLC, PSEG Fossil LLC,
Public Service Electric and Gas
Co.
Negative
FAC-003-X is not applicable since FAC-003-2 was approved by the BOT on November
4, 2011
Response: Thank you for your comment. You are correct that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 –
Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Hydro-Quebec TransEnergie
Negative
Hydro-Quebec TransEnergie is casting a negative vote again because our comment
from the last posting was not considered in the current draft: The minimum
frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of 50 degrees
North, the vegetation growth rates is limited. The Vegetation Inspection frequency in
the territories located above 50 degrees of latitude must be relaxed to 3 years.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and did not find this comment had been submitted as part of that project effort. No
changes made.
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Question 10 Comment
New Brunswick System
Operator
Negative
Since NBSO voted 'affirmative' for FAC-003-3, it makes sense for us to vote 'negative'
for this standard.
Response: Thank you for your comment. In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with
the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually
only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved
by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation
on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
PSEG Energy Resources &
Trade LLC/ Public Service
Electric and Gas Co./ PSEG
Fossil LLC
Negative
The phrase “generator Facility” should be “generator Transmission Facility,” and the
phrase “Transmission System” should be “Transmission system.”
Response: Thank you for your comment. We agree with your change to “Transmission system” but not to the addition of
“Transmission” in the phrase “generator Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part
because in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC. Therefore, the SDT
intentionally modified language so that a Facility owned by a generation entity did not contain the term “Transmission.”
SERC Reliability Corporation
Negative
There should not be a weak link under the standard. This proposed revision would
create a weak-link where a portion of the otherwise covered right-of-way would be
exposed.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 10 Comment
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
New York State Department
of Public Service/ National
Association of Regulatory
Utility Commissioners
Negative
Understand that there is an open issue regarding the availablility of generation
compliance documentation that needs to be satisfactorily addressed.
Response: The SDT does not understand your specific concern.
Infigen Energy US
Affirmative
Infigen supports the efforts of the SDT to ensure that Protection System
Misoperations affecting the reliability of the BES are thoroughly analyzed and
mitigated. Generator Owners are already analyzing Misoperations as/if they occur,
and are employing Corrective Action Plans to avoid future Misoperations. We support
maintaining "reasonable and appropriate" preventative measures and risk assessment
tools to ensure that misoperations are evaluated and corrected expediently.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC/PPL NERC
Registered Affiliates
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
SERC Reliability Corporation
Affirmative
The Generator Owner may be required to self-certify and report periodically to the
region whether they have become applicable to the standard.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc./ ACES Power
Marketing Standards
Collaborators/ ACES Power
Marketing
Affirmative
The modifications to PRC-004-2.1 R2 could be interpreted as requiring the GO to
analyze Protection System Misoperations on the generator interconnection Facility
even if it does not own the Facility. We suggest modifying the requirement as shown
below to address this issue.”The Generator Owner shall analyze Protection System
Misoperations on its generator and generator interconnection Facility that it owns ...”
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
SERC Reliability Corporation
Affirmative
With the understanding the Generator Interconnection FAcilities will be grouped with
Transmission Protection Systems for analysis at the regional level.
Response: Thank you for your comment and support.
Entergy Services
We suggest that the Vegetation Management Standards should be consistent for
both the TO and GO facilities. We would also like to suggest an additional
Recommendation for added clarity regarding Category 3 Outages (Off-ROW Fall-in
Outages). We understand that the Category 3 Outages are not a violation of the
Standard, but we feel that there should be some level of comment added within the
Standard clearly stating that these Outages are “Reportable Only” during the
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Quarterly Outage reports to the RE’s, and that there are no associated
violations/sanctions for this Category Of Outage, and that an Off-ROW fall-in outage
would not be considered an encroachment into the MVCD in any way. The Technical
Reference Document does a good job of clearly stating this in the Introduction on
Page 5 (“This standard is not intended to address outages such as those due to
vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human
activities or acts of nature.”) and we feel that this should also be stated clearly in the
Standard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”
The remainder of your comment is outside the scope of this SDT.
Southern Company
We agree with the 2010-17 Standard Drafting Team’s conclusion to not modify other
standards such as those mentioned on page 4 of the Technical Justification document.
In additon, we wish to provide the following support for exclusion of these specific
standards. Southern Company believes NERC’s Project 2010-07 SDT must challenge
making revisions to the standards included in the FERC order on Cedar Creek and
Milford. (This order supports NERC’s requirement for those entities to register as a
TO/TOP due to their ownership of generator interconnection circuits > 100kV.) We
believe there are clear technical and reliability-based reasons that support not adding
GO and GOP requirements to these standards and not requiring the GO or GOP to
register as a TO or TOP. Furthermore, we also believe there are clear distinctions
between GO/GOP responsibilities and TO/TOP responsibilities that must be
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 10 Comment
maintained to ensure BES reliability. Revising standards to assign TO/TOP
responsibilities to a GO/GOP or requiring a GO/GOP to register as a TO/TOP because
of generator interconnection circuits > 100kV will reduce the clarity of these
responsibilities. We have provided specific comments on each standard below:
EOP-005-1 R1, R2, R6, R7R1 and R2 require each TOP to have and maintain a system
restoration plan. R6 requires the TOP to train its operating personnel in
implementing this plan. R7 requires the TOP to verify its restoration plan by actual
testing or simulation. These requirements are clearly the role and responsibility of
the TOP, not a GO/GOP who happens to have generator interconnection facilities in
the TOP’s control area. The GOP’s roles and responsibilities are clearly and
appropriately addressed EOP-005-2. The presence of a generator interconnection
circuit > 100kV that happens to be owned by the GO instead of the TOP
fundamentally does not change the roles and responsibilities of the TOP or the GOP.
Thus, no changes due to EOP-005 are needed.
FAC-014-2, R2: FAC-014-2 R2 states “The Transmission Operator shall establish SOLs
(as directed by its Reliability Coordinator) for its portion of the Reliability Coordinator
Area that are consistent with its Reliability Coordinator’s SOL Methodology.” FAC014-2 R2 should not be revised to include GOPs. The GO is required by FAC-008-1 R1
and FAC-009-1 (FERC approved version) and pending FAC-008-3 R3 and R6 (FAC-008-3
filed with FERC for approval) to document the Facility Ratings for a GO-owned
generator interconnection circuit >100kV. The established Facility Rating must
respect the most limiting applicable equipment rating in the circuit and must consider
operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the GO to
the GOP if they are not the same entity. The operating voltage limits for this circuit
are established by the applicable TO/TOP, not the GO or GOP. Therefore, we believe
adding the GO to FAC-014-2 R2 would be redundant.
PER-003-1 R2, R2.1, R2.2PER-003-1 R2 and its sub-requirements state:”R2. Each
Transmission Operator shall staff its Real-time operating positions performing
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 10 Comment
Transmission Operator reliability-related tasks with System Operators who have
demonstrated minimum competency in the areas listed by obtaining and maintaining
one of the following valid NERC certificates (1 ) : [Risk Factor: High][Time Horizon:
Real-time Operations]: R2.1. Areas of Competency R2.1.1. Transmission operations
R2.1.2. Emergency preparedness and operations R2.1.3. System operations R2.1.4.
Protection and control R2.1.5. Voltage and reactive R2.2. Certificates o Reliability
Operator o Balancing, Interchange and Transmission Operator o Transmission
Operator This requirement is specifically for TOPs. Personnel training for GOPs needs
to be addressed separately and not mingled with responsibilities of the TOP. The
GOPs role in supporting BES reliability needs to be clearly understood and defined
prior to establishing training requirements in the standards.
PRC-001-1, R2, R2.2, R4, R6Generator Operators (GOPs) and the scope of protection
equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirement R2 and sub-requirement R2.2 The
language used in requirement R2 which applies to the GOP uses the general terms
“relay or equipment failures” which would include not only generator relaying, but
generator interconnection relaying in the GOPs scope as well. The GOP is required to
notify the TOP and Host BA in R2.1 “if a protective relay or equipment failure reduces
system reliability.” Requirement R2.2 requires the affected TOP to notify its RC and
affected TOPs and BAs. Thus, applying R2.2 to a GOP would be redundant to R2.1.
Requirement R4 states, “Each Transmission Operator shall coordinate protection
systems on major transmission lines and interconnections with neighboring
Generator Operators, Transmission Operators, and Balancing Authorities.” A
generator interconnection tie line does not constitute a ‘major tie line” or major
“interconnection with neighboring GOPs, TOPs, and BAs.” Thus, R4 should not be
revised to include GOPs. If a GO exists within NERC that does own such
interconnection facilities, the responsibility for coordination of protection systems on
such a line or interconnection should be the responsibility of the TOP in that area, not
the GO/GOP. This may require formal agreements between the TO/TOP and GO/GOP,
since the GO may own protection equipment on his end. The same logic applies to
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R6. R6 states, “Each Transmission Operator and Balancing Authority shall monitor the
status of each Special Protection System in their area, and shall notify affected
Transmission Operators and Balancing Authorities of each change in status.” This is
clearly the responsibility of the TOP and/or BA, not a GO/GOP who happens to have
generator interconnection facilities in the area. An SPS function by definition is to
maintain BES reliability. If a GO/GOP has equipment within the equipment scope of a
Special Protection System (SPS), responsibility for monitoring the SPS should be
conveyed in a formal agreement as appropriate.
TOP-001-1 R1Requirement R1 states, “Each Transmission Operator shall have the
responsibility and clear decision-making authority to take whatever actions are
needed to ensure the reliability of its area and shall exercise specific authority to
alleviate operating emergencies.” This is clearly the responsibility of the TOP, not a
GO/GOP who happens to have generator interconnection facilities in the TOP’s area.
Thus, R1 should not be applied to a GO/GOP who owns or operates generator
interconnection facilities. Furthermore, TOP-001-1 R3 (proposed to be covered in the
future in the proposed IRO-001-2 R2 and R3) appropriately requires the GOP to
comply with reliability directives issued by the TO “unless such actions would violate
safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the TOP the necessary decision-making authority over operation of all
generator Facilities up to the point of interconnection. They also give the GOP the
necessary authority to take appropriate actions to ensure safety and protection of the
GO’s equipment. Thus, no changes to TOP-001-1 are necessary.
TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4Requirement R6 and its sub-requirements state:
“R6. Transmission Operators, individually and jointly with other Transmission
Operators, shall develop, maintain, and implement formal policies and procedures to
provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional
reliability, including:R6.1. Monitoring and controlling voltage levels and real and
reactive power flows.R6.2. Switching transmission elements.R6.3. Planned outages of
transmission elements.R6.4. Responding to IROL and SOL violations.”These are clearly
Consideration of Comments: Generator Requirements at the Transmission Interface
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the responsibility of the TOP, not a GO/GOP who happens to have generator
interconnection facilities in the TOP’s area. Thus, these requirements should not be
applied to a GO/GOP who owns or operates generator interconnection facilities. The
same logic applies here as stated above in our discussion on TOP-001-1. We believe it
is inappropriate and would be adverse to BES reliability to apply these requirements
to a GOP. TOP-004-2 effectively gives the TOP the necessary decision-making
authority over operation of all generator Facilities up to the point of interconnection.
They also give the GOP the necessary authority to take appropriate actions to ensure
safety and protection of the GO’s equipment, such as opening high voltage generator
output breakers when required to protect the unit. Thus, no changes to TOP-004-2
are necessary.TOP-006-2 R3Requirement R3 states, “R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall provide appropriate technical
information concerning protective relays to their operating personnel. The intent of
this requirement when applied to a GOP is already addressed in PRC-001-1 R1 which
states, “Each Transmission Operator, Balancing Authority, and Generator Operator
shall be familiar with the purpose and limitations of protection system schemes
applied in its area.” Thus, no change to TOP-006-2 is necessary.   
Response: Thank you for your comment and support. We agree that there are clear and technical reliability-based reasons that
support not adding GO and GOP requirements to these standards and not requiring the GO or GOP to register as a TO or TOP. We
have expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement
cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and many of your explanations are
included therein.
American Wind Energy
Association
AWEA appreciates the opportunity to submit these comments on the NERC Project
2010-07. AWEA supports the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
Consideration of Comments: Generator Requirements at the Transmission Interface
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would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. AWEA supports the intent and goal of the SDT to ensure
that all generator-owned Facilities are appropriately covered under NERC’s Reliability
Standards. We also agree with the SDT that while many GO/GOPs operate Elements
and Facilities that might be considered by some entities to be Transmission, these are
most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore,
we support the SDT’s approach of identifying a very limited number of TO/TOP
standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP owners
of generator lead lines. We would be concerned, however, if additional requirements
were added beyond FAC-001, FAC-003, and PRC-004. Consideration of any additional
standards with respect to generator lead lines should be done on a standard-bystandard basis, reviewing the applicability of each standard as well as the impact on
the reliability of the Bulk Electric System.
Response: Thank you for your comment and support.
Bonneville Power
Administration
BPA thanks you for the opportunity to comment on Project 2010-07, Generator
Requirements at the Transmission Interface. BPA stands in support of the proposed
revisions and has no comments or concerns at this time.
Response: Thank you for your comment and support.
Constellation Power Source
Generation
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. While the revision process focuses on specific standards, it is
important to consider the reliability questions in the context of the full complement
Consideration of Comments: Generator Requirements at the Transmission Interface
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of reliability standards that apply to entities. For instance, the following standards
already apply to generators and relate to the reliability considerations around
transmission at the generator interface:
o PRC-001-1 addresses coordination of protection system components by requiring all
GOs to ensure coordination of their protection system with interconnected parties.
Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA, etc.
o PRC-004-1 requires all GOs to ensure that they analyze all misoperations on their
protection system which would include the protection of the tie line.
o TOP standards applicable to GOs aid coordination between a GO and a TO with
regards to the generator tie line by requiring all GOs to coordinate all maintenance
and emergency outages (both forced and planned) with all applicable interconnected
parties. Further, all ISO procedures require the same of GOs.
o RC, TOP and/or BA certified operators control and are responsible for overseeing
that transmission. According to the NERC functional model, a Generator Operator is
defined as “operat(ing) generating unit(s) and perform(ing) the functions of supplying
energy and reliability related services.” Given this limited scope, the Generator
Operator (GOP) cannot be considered as operating on the same level as the Reliability
Coordinator, Transmission Operator or Balancing Authority when it comes to real
time information on the status of the BES. The GOP does not monitor and control the
BES, rather the GOP only monitors and controls the generators that it operates and
relays information to other operating entities.
o IRO and TOP standards applicable to GOs include tie lines in their pool of resources
to alleviate operational emergencies by requiring all GOs to operate as directed by
their TOP, BA, or RC as directed and must render emergency assistance.
o FAC-8 and FAC-9 manage rating methodology consistency by requiring all GOs to
develop a methodology to rate all equipment, and that the RC has the authority to
challenge the GO on that methodology. The onus is on the GO to either change their
methodology and rating accordingly, or provide a technical justification as to why
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they cannot adopt the changes. Further, a generator will never be limited by its tie
line, as a generator’s profits are directly tied to its output. Therefore no generator
would limit its facility to the equipment that is delivering that output.
Response: Thank you for your comment and support. We agree that it is important to consider the reliability questions in the context
of the full complement of reliability standards, and we have endeavored to make these broader connections clear in our revised
technical justification document (posted under “Supporting Materials”). That document has been expanded to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and the kinds of further
justifications you also provided are included therein. After another thorough review of these standards, the SDT continues to believe
that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
Cowlitz County PUD
In answer to the SDT request for feedback on FERC's Order concerning Cedar Creek
and Milford, the District finds no technical reason to add any of the listed standard
requirements, and struggles to understand why FERC would even consider this listing
as applicable.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc.
In section 4.2.1 of the Applicability Section, “within” should be “with”. Because
NERC’s Glossary of Terms establishes that an Agreement can be verbal and not
enforceable by law, section 4.2.1 should be further modified to clarify that it is a
legally enforceable and fully executed Agreement. The language in R3 in parenthesis
after Generation Owner should be modified to “once required by Requirement R2”.
This makes it clearer that R3 does not apply until the GO has an executed Agreement
to evaluate a request by a third part to interconnect.
Response: Thank you for your comment. We agree that “within” should be “with.” The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
2
Organization
Yes or No
Manitoba Hydro
Question 10 Comment
Manitoba Hydro would also like to point out that if the redline changes are
implemented, it will greatly increase the complexity of coordination required under
FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Compliance & Responsbility
Organization
NextEra Energy, Inc. (NextEra) appreciates the work of the Project 2010-07 Generator
Requirements at the Transmission Interface Standard Drafting Team (SDT) on a
subject that NextEra has a significant interest in resolving. In fact, NextEra has been a
member of the SDT and an active observer. Given the recent events - such as (a) the
North American Electric Reliability Commission's draft interim directive; (b) the denial
of the Milford and Cedar Cheek requests for reconsideration at the Federal Energy
Regulatory Commission (FERC) and (c) the record in this case which, at times, suggests
the SDT needs to more formally consider the Milford and Cedar Cheek Reliability
Standards - NextEra requests that SDT more formally consider the merits of each
Reliability Standard adopted the Milford and Cedar Cheek FERC orders and the NERC
draft interim directive. Although NextEra does not condone the manner in which
NERC issued the interim draft directive and stated so in its comments to NERC on the
interim draft directive, NextEra’s overarching objective on this issue is to bring a
uniform, fair and technically supported approach that resolves the interface issue.
Thus, NextEra requests that the SDT (prior to proceeding any further or any additional
comments or votes on specific draft Reliability Standards) issue a technical paper that
point-by-point addresses the merits of including the Reliability Standards set forth in
the FERC Orders and NERC’s draft interim directive, and request stakeholder,
including NERC staff, comment. For example, this technical paper would likely the
merits of NERC’s draft interim directive not requiring NERC-certified operators (but
require training of interface operators), while FERC’s orders require NERC-certified
operators. While NextEra does not agree five days of training is necessary for an
interface operator, as the draft interim directive appears to propose, NextEra does
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
3
Organization
Yes or No
Question 10 Comment
believe a technical case can be made why NERC-certification is not required, and that
some degree of training related to the applicable Reliability Standards is reasonable.
Similar, on FAC-003 (as well as several other Standards), the draft interim directive
proposes a slightly different approach than the SDT. NextEra would rather these
approaches reconciled than be in conflict, with the potential for continued conflict as
the SDT’s work product proceeds. Further, NextEra requests that the SDT’s review
the technical merits of NERC’s proposed criteria to determine what generator
transmission lead is required to comply with additional Reliability Standards. As
noted, above, this technical paper should be posted for stakeholder, including NERC
staff, comment. Accordingly, while NextEra would have preferred that NERC and the
Regional Entities express there interim draft directive approach on the record in this
proceeding, NextEra believes it is appropriate for the SDT to draft a comprehensive
technical paper that, with an open approach, considers the inclusion of additional
Reliability Standards, if appropriate, as a way of building lasting support for its
approach.
Response: Thank you for your comment and support. We certainly agree that is important for NERC staff and the SDT to continue to
work together to try to develop a mutually agreed upon solution for dealing with this reliability gap, and to a certain extent, the SDT
has tried to provide the kind of technical paper you suggest in its modified technical justification document (posted under “Supporting
Materials”), which has been expanded to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by
NERC in its draft compliance directive. The SDT does not, at this point, plan to develop a technical paper that discusses the merits of
the standards introduced by FERC and NERC, because its current focus is on filing the FAC-001-1, FAC-003-3, and PRC-004-2.1a with
FERC. As it moves forward to a final solution, however, this kind of technical paper may prove useful. We appreciate the suggestion.
Dominion
No
Tennessee Valley Authority
No
Exelon
PRC-004 - suggest that the Standard state that responsibility for the analysis of
missoperations of protective equipment shall be the responsibility of the owner of the
protective equipment.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
4
Organization
Yes or No
Question 10 Comment
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
ReliabiltiyFirst
ReliabilityFist has found a number of editiorial erros for the FAC-001-1 VSLs. They
include the following:1. VSL R1 - should not reference sub-requirements, should
reference the sub-parts consistent with the requirement (i.e. Requirement R1, Part
1.1, 1.2 or 1.3) 2. VSL for R3 - the VSL should referenced Requirement 3, Part 3.1.1
through 3.1.16 rather than what is currently stated (Requirement R3, Part 3.1.1
R3.1.6)
Response: Thank you for your comment. While we agree that the VSLs for R1 need to be updated, that change is outside the scope of
this SDT because our changes are limited to those that incorporate the GO into the applicability of the requirement; the team made
no changes to R1 as it only includes the TO. We have, however, made the suggested changes to the VSLs for R3.
RES Americas Development
RES and AWEA appreciates the opportunity to submit these comments on the NERC
Project 2010-07. We support the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. RES and AWEA supports the intent and goal of the SDT to
ensure that all generator-owned Facilities are appropriately covered under NERC’s
Reliability Standards. We also agree with the SDT that while many GO/GOPs operate
Elements and Facilities that might be considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as
such should not be subject to the same standards applicable to TO/TOPs, who own
and operate Transmission Elements and Facilities that are part of the integrated grid.
Therefore, we support the SDT’s approach of identifying a very limited number of
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
5
Organization
Yes or No
Question 10 Comment
TO/TOP standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP
owners of generator lead lines. We would be concerned, however, if additional
requirements were added beyond FAC-001, FAC-003, and PRC-004. Consideration of
any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the
impact on the reliability of the Bulk Electric System.
Sempra Generation
Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
SERC Planning Standards
Subcommittee/ SERC OC
Standards Review Group
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
6
END OF REPORT
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
11
7
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Draft 3: December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission systems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 3: December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission systems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 3: December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 3: December 1, 2011
4 of 5
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Draft 3: December 1, 2011
5 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner within an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission sSystems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
sSystems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Draft 32: August 31December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission sSystems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission sSystems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 32: August 31December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission sSystems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 32: August 31December 1, 2011
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission
sSystems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission
sSystems.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission
sSystems.
R3 The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 32: August 31December 1, 2011
4 of 5
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
sSystems.
The responsible
entity’s Facility
connection
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements failed to
address one of the
pParts listed in
Requirement R3,
pParts 3.1.1 through
R3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through
3.1.16.Parts listed in
Requirement R3, Part
3.1.1 R3.1.6.
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16Parts listed in
Requirement R3,
Part 3.1.1 R3.1.6.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Draft 32: August 31December 1, 2011
5 of 5
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
Introduction
B.A.
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish facilityFacility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
April 1, 2005
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
C.B. Requirements
R1. The Transmission Owner shall document, maintain, and publish facilityFacility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability OrganizationEntity, subregional, Power Pool, and individual Transmission Owner
planning criteria and facilityFacility connection requirements. The Transmission Owner’s
facilityFacility connection requirements shall address connection requirements for:
R1.1.1.1.
Generation facilities,Facilities,
R1.2.1.2.
Transmission facilitiesFacilities, and
R1.3.1.3.
End-user facilitiesFacilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
1 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
R2.1.3.1.
Provide a written summary of its plans to achieve the required system
performance as described abovein Requirements R1 or R2 throughout the planning
horizon:
R2.1.1.3.1.1. Procedures for coordinated joint studies of new facilitiesFacilities and
their impacts on the interconnected transmissionTransmission systems.
R2.1.2.3.1.2. Procedures for notification of new or modified facilitiesFacilities to
others (those responsible for the reliability of the interconnected
transmissionTransmission systems) as soon as feasible.
R2.1.3.3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
R2.1.4.3.1.4.
Breaker duty and surge protection.
R2.1.5.3.1.5.
System protection and coordination.
R2.1.6.3.1.6.
Metering and telecommunications.
R2.1.7.3.1.7.
Grounding and safety issues.
R2.1.8.3.1.8.
Insulation and insulation coordination.
R2.1.9.3.1.9.
Voltage, Reactive Power, and power factor control.
R2.1.10.3.1.10. Power quality impacts.
R2.1.11.3.1.11. Equipment Ratings.
R2.1.12.3.1.12. Synchronizing of facilitiesFacilities.
R2.1.13.3.1.13. Maintenance coordination.
R2.1.14.3.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15.3.1.15. Inspection requirements for existing or new facilitiesFacilities.
R2.1.16.3.1.16. Communications and procedures during normal and emergency
operating conditions.
[VRF – Medium]
R3.R4. The Transmission Owner shall maintain and update its facilityFacility connection
requirements as required. The Transmission Owner shall make documentation of these
requirements available to the users of the transmission system, the Regional Reliability
OrganizationEntity, and NERCERO on request (five business days).
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
2 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
[VRF – Medium]
D.C. Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for
inspectionEnforcement Authority) evidence that it met all the requirements stated in
Reliability Standard FAC-001-0_Requirement R1.
M2. TheEach Generator Owner that has an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used
to interconnect to the interconnected Transmission Ownersystems shall make available (to its
Compliance Monitor) for inspectionEnforcement Authority) evidence that it met all
requirements stated in Reliability Standard FAC-001-0_Requirement R2.
M3. TheEach Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Monitor) for inspectionEnforcement
Authority) evidence that it met all the requirements stated in Reliability Standard FAC-0010_R3Requirement R3.
M3.M4. The Transmission Owner shall make available (to its Compliance Enforcement
Authority) evidence that it met all the requirements stated in Requirement R4.
E.D. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
Compliance Monitor: Regional Reliability Organization.Entity
1.2.
Compliance Monitoring Period and Reset TimeframeEnforcement Processes:
On request (five business days).
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
None specified.
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
3 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
Failed to include one
High VSL
Severe VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
Failed to document or
maintain or publish its
Facility connection
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
4 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
F.E. Regional Differences
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
5 of 6
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
6 of 6
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval,
NERC staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT
will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-0032) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of
eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because
if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003X to ensure that there is a functional entity responsible for managing vegetation on the piece of line
commonly known as the generator interconnection Facility.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity and the North American Electric Reliability Council (NERC).
Applicability:
With the line of sight reference in
4.1. Regional Entity.
4.3.1, the SDT simply seeks to clarify
the exception language based on the
4.2. Applicable Transmission Owner
intent that has been agreed upon by
4.2.1. Transmission Owner that owns overhead
the stakeholder body. In its
transmission lines operated at 200 kV
Consideration of Comments report
and above and to any lower voltage lines
from
the last formal comment period,
designated by the Regional Entity as
which
ended on July 17, 2011, the
critical to the reliability of the electric
SDT
explained
“We believe that the
system in the region.
one mile length is a reasonable
4.3. Applicable Generator Owner
approximation of line of sight, and
4.3.1. Generator Owner that owns an overhead
that using a fixed starting point (at the
transmission line(s) that extends greater
fenced area of the generation station
than one mile (1.609 kilometers) beyond
switchyard) eliminates confusion and
the fenced area of the generating station
any discretion on the part of a
switchyard up to the point of
Generator Owner or an auditor.” With
interconnection with a Transmission
the addition of an explicit line of sight
Owner’s Facility or does not have a clear
reference here, the SDT believes it has
line of sight from the switchyard fence to
clarified its original intent.
the point of interconnection and is
operated at 200 kV and above, and any lower voltage lines designated by the
Regional Entity as critical to the reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
2 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R1 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
4 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
5 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
6 of 12
Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
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Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
smaller than its
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Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
9 of 12
Draft 3: December 1, 2011
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
Standard FAC-003-X — Transmission Vegetation Management Program
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
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Draft 3: December 1, 2011
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
Standard FAC-003-X — Transmission Vegetation Management Program
R3
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
vegetation
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
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Draft 3: December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
footer.
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
12 of 12
Draft 3: December 1, 2011
Revision under Project
2010-07
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
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Standard FAC-003-X — Transmission Vegetation Management Program
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval,
NERC staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT
will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-0032) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of
eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because
if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003X to ensure that there is a functional entity responsible for managing vegetation on the piece of line
commonly known as the generator interconnection Facility.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
With the line of sight reference in
4.1. Regional Entity.
4.3.1, the SDT simply seeks to clarify
the exception language based on the
4.2. Applicable Transmission Owner
intent that has been agreed upon by
4.2.1. Transmission Owner that owns overhead
the stakeholder body. In its
transmission lines operated at 200 kV
Consideration of Comments report
and above and to any lower voltage lines
from the last formal comment period,
designated by the Regional Entity as
which ended on July 17, 2011, the
critical to the reliability of the electric
SDT explained “We believe that the
system in the region.
one mile length is a reasonable
4.3. Applicable Generator Owner
approximation of line of sight, and
4.3.1. Generator Owner that owns an overhead
that using a fixed starting point (at the
transmission line(s) that extends greater
fenced area of the generation station
than one mile or (1.609 kilometers)
switchyard) eliminates confusion and
beyond the fenced area of the generating
any discretion on the part of a
station switchyard up to the point of
Generator Owner or an auditor.” With
interconnection with a Transmission
the addition of an explicit line of sight
Owner’s Facility or does not have a clear
reference here, the SDT believes it has
line of sight from the switchyard fence to
clarified its original intent.
the point of interconnection and is
operated at 200 kV and above, and any lower voltage lines designated by the
Regional Entity as critical to the reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
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Standard FAC-003-X — Transmission Vegetation Management Program
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 R1 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 1.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
1
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
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Standard FAC-003-X — Transmission Vegetation Management Program
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
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Standard FAC-003-X — Transmission Vegetation Management Program
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
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Standard FAC-003-X — Transmission Vegetation Management Program
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
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Standard FAC-003-X — Transmission Vegetation Management Program
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
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Standard FAC-003-X — Transmission Vegetation Management Program
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
smaller than its
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Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
9 of 12
Draft 23: August 31December 1, 2011
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
Standard FAC-003-X — Transmission Vegetation Management Program
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
10 of 12
Draft 23: August 31December 1, 2011
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
Standard FAC-003-X — Transmission Vegetation Management Program
R3
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
vegetation
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
11 of 12
Draft 23: August 31December 1, 2011
Standard FAC-003-X — Transmission Vegetation Management Program
footer.
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
12 of 12
Draft 23: August 31December 1, 2011
Revision under Project
2010-07
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 3: Revised December 1, 2011
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 3: Revised December 1, 2011
2
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 3: Revised December 1, 2011
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
3
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 3: December 1, 2011
4
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this
approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities. The
Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved
FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to
carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by
FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator
interconnection Facility.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1.
4.2.
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
4.1.2.1.
4.2.
Generator Owners that own generation Facilities defined in 4.3
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands owned
by federal 1, state, provincial, public, private, or
tribal entities:
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 3: December 1, 2011
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
5
addressing the areas where the standard
does and does not apply makes the
standard clearer.
FAC-003-3 — Transmission Vegetation Management
4.2.1.
Each overhead transmission line operated at 200kV or higher.
4.2.2.
Each overhead transmission line operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3.
Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.
4.2.4.
Each overhead transmission line identified above (4.2.1 through 4.2.3)
located outside the fenced area of the switchyard, station or substation and
any portion of the span of the transmission line that is crossing the
substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross
lands owned by federal 2, state, provincial,
Within the text of NERC Reliability
public, private, or tribal entities:
Standard FAC-003-3, “transmission
line(s) and “applicable line(s) can
4.3.1.
Overhead transmission lines that extend
also refer to the generation Facilities
greater than one mile (1.609 kilometers)
as referenced in 4.3 and its
beyond the fenced area of the
subsections.
generating switchyard or do not have a
clear line of sight from the switchyard
fence to the point of interconnection
With the line of sight reference in
and are:
4.3.1, the SDT simply seeks to
clarify the exception language based
4.3.1.1.
Operated at 200kV or higher; or
on the intent that has been agreed
upon by the stakeholder body. In its
4.3.1.2.
Operated below 200kV
Consideration of Comments report
identified as an element of an IROL under
from
the last formal comment period,
NERC Standard FAC-014 by the Planning
which ended on July 17, 2011, the
Coordinator; or
SDT explained “We believe that the
one mile length is a reasonable
4.3.1.3.
Operated below 200 kV
approximation of line of sight, and
identified as an element of a Major WECC
that using a fixed starting point (at
Transfer Path in the Bulk Electric System by
the fenced area of the generation
WECC.
station switchyard) eliminates
Enforcement:
confusion and any discretion on the
part of a Generator Owner or an
The Requirements within a Reliability Standard govern and
auditor.” With the addition of an
will be enforced. The Requirements within a Reliability
explicit line of sight reference here,
Standard define what an entity must do to be compliant and
the SDT believes it has clarified its
binds an entity to certain obligations of performance under
original intent.
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 3: December 1, 2011
6
FAC-003-3 — Transmission Vegetation Management
Section 215 of the Federal Power Act. Compliance will in all cases be measured by determining
whether a party met or failed to meet the Reliability Standard Requirement given the specific
facts and circumstances of its use, ownership or operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
Draft 3: December 1, 2011
7
FAC-003-3 — Transmission Vegetation Management
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
Draft 3: December 1, 2011
8
FAC-003-3 — Transmission Vegetation Management
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 3: December 1, 2011
9
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 3: December 1, 2011
10
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 3: December 1, 2011
11
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 3: December 1, 2011
12
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
R6. Each applicable Transmission Owner and
applicable Generator Owner shall
perform a Vegetation Inspection of 100%
of its applicable transmission lines
(measured in units of choice - circuit,
pole line, line miles or kilometers, etc.) at
least once per calendar year and with no
more than 18 calendar months between
inspections on the same ROW 6 [Violation
Risk Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Inspections are used by applicable Transmission
Owners and applicable Generator Owners to
assess the condition of the entire ROW. The
information from the assessment can be used to
determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar year
but with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America and
on common utility practice, this minimum
frequency is reasonable. Transmission Owners
should consider local and environmental factors
that could warrant more frequent inspections.
6
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 3: December 1, 2011
13
FAC-003-3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 3: December 1, 2011
14
FAC-003-3 — Transmission Vegetation Management
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
Draft 3: December 1, 2011
15
FAC-003-3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Draft 3: December 1, 2011
16
FAC-003-3 — Transmission Vegetation Management
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 3: December 1, 2011
17
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 3: December 1, 2011
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
18
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
Long-Term
Planning
Real-time
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
Lower
Medium
R5
Operations
Planning
Medium
R6
Operations
Medium
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
The responsible entity
Draft 3: December 1, 2011
The responsible entity failed
The responsible entity failed to
19
The responsible entity failed to
FAC-003-3 — Transmission Vegetation Management
Planning
R7
Operations
Planning
Medium
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 3: December 1, 2011
20
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 3: December 1, 2011
21
FAC-003-3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line
solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is
incorporating the line into the interconnected electrical energy transmission network which will thereafter make the line subject to the
standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line solely for
local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is incorporating
the line into the interconnected electrical energy transmission network. In this special case the line upon acquisition was designated as
an element of an Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 3: December 1, 2011
22
FAC-003-3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to
lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not
elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 3: December 1, 2011
23
FAC-003-3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner or Reliability Coordinator to protect an Interconnection may
cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner to manage vegetation and to the corresponding performance level of the
Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation related outages
that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or applicable Generator
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to
the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines operated at nominal voltage levels not listed
in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on the next highest nominal
voltage in the table to determine an acceptable distance.
Draft 3: December 1, 2011
24
FAC-003-3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to
the transmission system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the
competency of the applicable Transmission Owner or applicable Generator Owner in managing vegetation. There are many
acceptable approaches to manage vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner chooses to use will
generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 3: December 1, 2011
25
FAC-003-3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially
threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular
service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner employee who personally identifies such a threat in the field. Confirmation
could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 3: December 1, 2011
26
FAC-003-3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to ensure the proper communication
between field personnel and the control center to allow the control center to take the appropriate action until or as the vegetation threat
is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or other
preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners may have a danger tree identification program that identifies trees
for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an
immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance.
The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or applicable Generator
Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or applicable Generator Owner’s rights, or other
circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A
wide range of actions can be taken to address various situations. General considerations include:
Draft 3: December 1, 2011
27
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner is constrained from
performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner could consider location specific measures such as modifying the inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could
include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document and track the specific corrective
action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner may determine that more
frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as anticipated growth rates of
the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner may choose units such as: circuit,
pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates 2,000 miles of applicable transmission
lines this applicable Transmission Owner or applicable Generator Owner will be responsible for inspecting all the 2,000 miles of lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then
the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 3: December 1, 2011
28
FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner is required to complete its an
annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the
transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner provide evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles of applicable
transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s annual plan, the
applicable Transmission Owner or applicable Generator Owner will be responsible completing those identified miles. If a applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan that does not put the transmission system
at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the calculation
to determine what percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan,
or 900 / 900 = 100% completed annual miles. If an applicable Transmission Owner or applicable Generator Owner only completed
875 of the total 1000 miles with no acceptable documentation for modification of the annual plan the calculation for failure to
complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual
plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a
major storm could require redirecting local resources away from planned maintenance. This situation may also include complying
with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan
provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full
extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 3: December 1, 2011
29
FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable Transmission Owners
or applicable Generator Owners may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator Owner, evidence of successful annual work plan execution could consist
of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed
work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 3: December 1, 2011
30
FAC-003-3 — Transmission Vegetation Management
Draft 3: December 1, 2011
31
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 3: December 1, 2011
32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 3: December 1, 2011
33
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 3: December 1, 2011
34
FAC-003-3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 3: December 1, 2011
35
FAC-003-3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 3: December 1, 2011
36
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
Draft 3: December 1, 2011
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
37
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 23: Revised November 9December 1, 2011
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 23: Revised November 9December 1, 2011
2
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
Draft 23: Revised November 9December 1, 2011
3
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 23: September 29December 1, 2011
4
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this
approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities. The
Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved
FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to
carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by
FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator
interconnection Facility.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
4.1.1.1.
4.2.
Applicable Transmission Owners
4.1.2.
4.1.2.1.
4.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
Generator Owners that own generation Facilities defined in 4.3
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands owned
by federal 1, state, provincial, public, private, or
tribal entities:
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 23: September 29December 1, 2011
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
5
addressing the areas where the standard
does and does not apply makes the
standard clearer.
FAC-003-3 — Transmission Vegetation Management
4.2.1.
Each overhead transmission line operated at 200kV or higher.
4.2.2.
Each overhead transmission line operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning
Coordinator.
4.2.3.
Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.
4.2.4.
Each overhead transmission line identified above (4.2.1 through 4.2.3)
located outside the fenced area of the switchyard, station or substation and
any portion of the span of the transmission line that is crossing the
substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross
lands owned by federal 2, state, provincial,
Within the text of NERC Reliability
public, private, or tribal entities:
Standard FAC-003-3, “transmission
line(s) and “applicable line(s) can
4.3.1.
Overhead transmission lines that extend
also refer to the generation Facilities
greater than one mile or (1.609
as referenced in 4.3 and its
kilometers) beyond the fenced area of
subsections.
the generating switchyard or do not
have a clear line of sight from the
switchyard fence to the point of
With the line of sight reference in
interconnection and are:
4.3.1, the SDT simply seeks to
clarify the exception language based
4.3.1.1.
Operated at 200kV or higher; or
on the intent that has been agreed
upon by the stakeholder body. In its
4.3.1.2.
Operated below 200kV
Consideration of Comments report
identified as an element of an IROL under
from the last formal comment period,
NERC Standard FAC-014 by the Planning
which ended on July 17, 2011, the
Coordinator; or.
SDT explained “We believe that the
one mile length is a reasonable
4.3.1.3.
Operated below 200 kV
approximation of line of sight, and
identified as an element of a Major WECC
that using a fixed starting point (at
Transfer Path in the Bulk Electric System by
the fenced area of the generation
WECC.
station switchyard) eliminates
Enforcement:
confusion and any discretion on the
part of a Generator Owner or an
The Requirements within a Reliability Standard govern and
auditor.” With the addition of an
will be enforced. The Requirements within a Reliability
explicit line of sight reference here,
Standard define what an entity must do to be compliant and
the SDT believes it has clarified its
binds an entity to certain obligations of performance under
original intent.
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 23: September 29December 1, 2011
6
FAC-003-3 — Transmission Vegetation Management
Section 215 of the Federal Power Act. Compliance will in all cases be measured by determining
whether a party met or failed to meet the Reliability Standard Requirement given the specific
facts and circumstances of its use, ownership or operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
Draft 23: September 29December 1, 2011
7
FAC-003-3 — Transmission Vegetation Management
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
Draft 23: September 29December 1, 2011
8
FAC-003-3 — Transmission Vegetation Management
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 23: September 29December 1, 2011
9
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 3 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 4,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 5,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
3
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
4
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
5
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 23: September 29December 1, 2011
10
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 23: September 29December 1, 2011
11
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 23: September 29December 1, 2011
12
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or evidence that the line was de-energized. (R5)
R6. Each applicable Transmission Owner and
applicable Generator Owner shall
perform a Vegetation Inspection of 100%
of its applicable transmission lines
(measured in units of choice - circuit,
pole line, line miles or kilometers, etc.) at
least once per calendar year and with no
more than 18 calendar months between
inspections on the same ROW 6 [Violation
Risk Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Inspections are used by applicable Transmission
Owners and applicable Generator Owners to
assess the condition of the entire ROW. The
information from the assessment can be used to
determine risk, determine future work and
evaluate recently-completed work. This
requirement sets a minimum Vegetation
Inspection frequency of once per calendar year
but with no more than 18 months between
inspections on the same ROW. Based upon
average growth rates across North America and
on common utility practice, this minimum
frequency is reasonable. Transmission Owners
should consider local and environmental factors
that could warrant more frequent inspections.
6
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 23: September 29December 1, 2011
13
FAC-003-3 — Transmission Vegetation Management
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 7
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
7
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 23: September 29December 1, 2011
14
FAC-003-3 — Transmission Vegetation Management
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
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15
FAC-003-3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
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16
FAC-003-3 — Transmission Vegetation Management
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 23: September 29December 1, 2011
17
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 32: September 29December 1, 2011
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
18
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
Long-Term
Planning
Real-time
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
Lower
Medium
R5
Operations
Planning
Medium
R6
Operations
Medium
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
The responsible entity
Draft 32: September 29December 1, 2011
The responsible entity failed
The responsible entity failed to
19
The responsible entity failed to
FAC-003-3 — Transmission Vegetation Management
Planning
R7
Operations
Planning
Medium
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 32: September 29December 1, 2011
20
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 32: September 29December 1, 2011
21
FAC-003-3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line
solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is
incorporating the line into the interconnected electrical energy transmission network which will thereafter make the line subject to the
standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line solely for
local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is incorporating
the line into the interconnected electrical energy transmission network. In this special case the line upon acquisition was designated as
an element of an Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 32: September 29December 1, 2011
22
FAC-003-3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to
lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not
elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 32: September 29December 1, 2011
23
FAC-003-3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner or Reliability Coordinator to protect an Interconnection may
cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner to manage vegetation and to the corresponding performance level of the
Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation related outages
that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or applicable Generator
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to
the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines operated at nominal voltage levels not listed
in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on the next highest nominal
voltage in the table to determine an acceptable distance.
Draft 32: September 29December 1, 2011
24
FAC-003-3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to
the transmission system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the
competency of the applicable Transmission Owner or applicable Generator Owner in managing vegetation. There are many
acceptable approaches to manage vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner chooses to use will
generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 32: September 29December 1, 2011
25
FAC-003-3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially
threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular
service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner employee who personally identifies such a threat in the field. Confirmation
could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 32: September 29December 1, 2011
26
FAC-003-3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to ensure the proper communication
between field personnel and the control center to allow the control center to take the appropriate action until or as the vegetation threat
is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or other
preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners may have a danger tree identification program that identifies trees
for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an
immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance.
The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or applicable Generator
Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or applicable Generator Owner’s rights, or other
circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A
wide range of actions can be taken to address various situations. General considerations include:
Draft 32: September 29December 1, 2011
27
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner is constrained from
performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner could consider location specific measures such as modifying the inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could
include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document and track the specific corrective
action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner may determine that more
frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as anticipated growth rates of
the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner may choose units such as: circuit,
pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates 2,000 miles of applicable transmission
lines this applicable Transmission Owner or applicable Generator Owner will be responsible for inspecting all the 2,000 miles of lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then
the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 32: September 29December 1, 2011
28
FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner is required to complete its an
annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the
transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner provide evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles of applicable
transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s annual plan, the
applicable Transmission Owner or applicable Generator Owner will be responsible completing those identified miles. If a applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan that does not put the transmission system
at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the calculation
to determine what percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan,
or 900 / 900 = 100% completed annual miles. If an applicable Transmission Owner or applicable Generator Owner only completed
875 of the total 1000 miles with no acceptable documentation for modification of the annual plan the calculation for failure to
complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual
plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a
major storm could require redirecting local resources away from planned maintenance. This situation may also include complying
with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan
provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full
extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 32: September 29December 1, 2011
29
FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable Transmission Owners
or applicable Generator Owners may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator Owner, evidence of successful annual work plan execution could consist
of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed
work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 32: September 29December 1, 2011
30
FAC-003-3 — Transmission Vegetation Management
Draft 32: September 29December 1, 2011
31
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 8
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 9
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
8
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
9
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 32: September 29December 1, 2011
32
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 32: September 29December 1, 2011
33
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 32: September 29December 1, 2011
34
FAC-003-3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 32: September 29December 1, 2011
35
FAC-003-3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 32: September 29December 1, 2011
36
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 32: September 29December 1, 2011
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
37
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity.
Dc e m b e r 1, 2011
1 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
2.1
XX
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
Revision under Project
2010-07
Dc e m b e r 1, 2011
2 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity.
Au g u s t 31Dc e m b e r 1, 2011
1 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
32.1
XX
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
Revision under Project
2010-07
Au g u s t 31Dc e m b e r 1, 2011
2 of 2
Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: The first day of the first calendar quarter, one year after
applicable In those jurisdictions where regulatory approval; or in is required, all requirements
become effective upon approval. In those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter one year afterall requirements become
effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Dc e m be r 1, 2011
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Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.1. Compliance Enforcement Authority
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
2.1
XX
Errata change: Edited R2 to add “…and
Revision under Project
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Dc e m be r 1, 2011
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Standard PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
generator interconnection Facility…”
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010Dc e m be r 1, 2011
2010-07
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Implementation Plan for FAC-001-1—Facility
Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired at midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify one existing requirement (now R3)). Therefore, this implementation plan only
identifies a compliance timeframe for Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Implementation Plan for FAC-003-3—
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC glossary upon approval of FAC-003-3, or the above definition of
Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at midnight the
day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has been
approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on order in which regulatory authorities approved FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming (as is required by
FAC-003-3 Requirement 1.3). Once a complete inventory is created, the Generator Owner will begin
the process of gathering information for the TVMP. In instances where the generation interconnection
Facilities are owned by a partnership, a majority or operating partner will need to obtain partnership
Implementation Plan for FAC-003-3
2
approval to proceed with procurement of a TVMP expert, and later a tree trimming crew. Typically, a
request for proposal to hire TVMP consultant is initiated which could take several weeks in order to
obtain sufficient bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received,
a contract with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator Owner
staff and the TVMP consultant will need to perform a Right-of-Way inspection (as required in FAC-0033 Requirement 1), usually done using GPS, LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-003-3
Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation (as required in FAC-003-3
Requirement 1.2). On an ongoing basis, in addition to performing inspections and clearances as
required by the entity's TVMP, the Generator Owner will need to ensure that the training and
qualification requirements for the standard are met. The entity will also need to maintain
documentation of all FAC-003-3 activities for compliance period of one year to meet compliance with
the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
Implementation Plan for FAC-003-3
3
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
Implementation Plan for FAC-003-3
4
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
5
Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired at midnight the day before FAC-003-X becomes effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
1
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMP and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
3
Implementation Plan for PRC-004-2.1—
Analyis of Transmission and Generation
Protection System Misoperations
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-004-2 will
be retired when PRC-004-2.1 becomes effective.
Compliance with Standard
The proposed change to Requirement R2 is a clarifying change. While there was no reliability gap in the
previous version of the standard, if applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection System
Misoperations, exclusive of its generator interconnection Facility. The errata change to R2 makes clear
that generator interconnection Facilities are also part of Generator Owners’ responsibility in the
context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption.
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. Many of these standards and requirements had been addressed in
the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad
Hoc Report) and additional standards were reviewed as a result of informal discussions with NERC and
FERC staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004 and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new,
glossary terms.
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Project 2010-07 Technical Justification Document
2
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT agrees
with that intended exclusion in principle; as it discusses in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT recognizes that in
many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2)
the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for
exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, sections 4.3.1 of both
versions of FAC-003 (which address applicable generation Facilities) now state: “Overhead transmission
Project 2010-07 Technical Justification Document
3
lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating
switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…” The SDT took into consideration all comments submitted in both formal
comment periods, and believes that this exemption now adequately addresses the reliability impact for
a majority of the Facilities, while balancing the efforts necessary to support the standard from all
entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
Project 2010-07 Technical Justification Document
4
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
Ad Hoc Report*
X
X
X
X
X
X
X
NERC Directive
FERC Order
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
Project 2010-07 Technical Justification Document
5
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
Project 2010-07 Technical Justification Document
6
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
Project 2010-07 Technical Justification Document
7
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Project 2010-07 Technical Justification Document
8
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
Project 2010-07 Technical Justification Document
9
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
Project 2010-07 Technical Justification Document
10
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Project 2010-07 Technical Justification Document
11
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
Project 2010-07 Technical Justification Document
12
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
Project 2010-07 Technical Justification Document
13
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
Project 2010-07 Technical Justification Document
14
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
15
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. The majorityMany of these standards and requirements had been
addressed in the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface (Ad Hoc Report),) and additional standards have beenwere reviewed, and will continued to
be reviewed, as a result of informal discussions with NERC and FERC staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby radialsole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
radialsole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate radialsole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, would require
substantially more data and modeling responsibilities, and would detract from the entities’ primary
functions: to own and operate their generation equipment – including any Facilities owned and
operated at voltages of 100 kV or greater that connect to the interconnected system – in a reliable
manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document). with the statement that the alert applied to
generator interconnection tie lines that are radial only and do not serve load “if the generator is
considered part of the bulk electric system”). While this applies to a specific NERC Recommendation,
the SDT considers this compelling evidence that the paradigm for thinking about generator
interconnection Facilities is shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004. and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and to postpone discussions onnot, at this time, propose revisions to
existing, or creation of new, definitions until the standards have been successfully balloted. glossary
terms.
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
Project 2010-07 Technical Justification Document
2
additional standards that had been proposed for substantive modification in the Ad Hoc Report.and
requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that
a regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). After reviewing
formal comments, the The SDT agreed to revise theagrees with that intended exclusion so that it
applies to a Facility if its length is “one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard” to approximate line of sign from a fixed point. Other than revising this
exclusion,in principle; as it discusses in the document titled “Technical Justification Project 2010-07
Generator Requirements at the Transmission Interface,” the SDT applied the same criteria to the
Generator Owner as applies to the Transmission Owner in the current FERC approved version of this
standard as well as one approved by stakeholders (under Project 2007-07) in February 2011. The SDT is
Project 2010-07 Technical Justification Document
3
communicating with NERC staffrecognizes that in many cases, generation Facilities are (1) staffed and
the Project 2007-07 SDT to ensure that changes to this standard will be coordinated before submitting
to NERC’s Board of Trustees, but feels compelled to continue to posting both versions until the
outcome of Project 2007-07 efforts is cleareroverhead portion is within line of sight or (2) the overhead
Facility is over a paved surface. Stakeholders have generally supported the rationale for exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, sections 4.3.1 of both
versions of FAC-003 (which address applicable generation Facilities) now state: “Overhead transmission
lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating
switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…” The SDT took into consideration all comments submitted in both formal
comment periods, and believes that this exemption now adequately addresses the reliability impact for
a majority of the Facilities, while balancing the efforts necessary to support the standard from all
entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other SubstantiveStandards Considered by the Standard Modifications from the
Ad Hoc ReportDrafting Team
Project 2010-07 Technical Justification Document
4
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. Below, the SDT provides its reasons for not proposing the substantive changes
that were included in the Ad Hoc Report (that is, a change in applicability or new requirement, beyond
simply adding the text “including its Generator Interconnection Facility” to an existing requirement).
As Project 2010-07 continues, the SDT will work with FERC staff, NERC staff, and industry groups to
determine if its list of proposed standards is supported industry-wide, and whether other standards
need to be considered.During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
Ad Hoc Report*
X
X
X
X
X
X
X
Project 2010-07 Technical Justification Document
NERC Directive
FERC Order
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
5
TOP-008-1
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
infersimplies that Generator Operators need to provide their underfrequency settings to their
respective Transmission Operator. Further, Generator Operators typically do not have the technical
expertise or access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Project 2010-07 Technical Justification Document
6
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
Project 2010-07 Technical Justification Document
7
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
Project 2010-07 Technical Justification Document
8
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially arrived at this decisiondetermined that IRO-005-2 did not require
modification because of the plannedOctober 2011 retirement of IRO-005-2the standard. In subsequent
meetings, the SDT also reached the conclusion that there is no reliability gap as PRC-001-1 R2 already
requires the Generator Operator to notify reliability entities of relay or equipment failures. The SDT
believes that a Special Protection System is a form of protection system and therefore any degradation
or potential failure to operate as expected would be required to be reported by the Generator
Operator to reliability entities (Balancing Authorities, Transmission Operators, and Reliability
Coordinators).
Personnel Perform ance, Training, and Qualifications (PER) Standards
Project 2010-07 Technical Justification Document
9
The SDT also chose not to propose the revisionsPER Standards (PER-001-0 and PER-002-0 were
addressed in the Ad Hoc Report; PER-002-0 was addressed in the NERC Directive; and PER-003-1 was
addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority orand PER-002-0—Operating Personnel Training that were proposed by the Ad Hoc Group..
For PER-001-0, the Ad Hoc Group had proposed adding a new R2 that would read “Each Generator
Operator shall provide operating personnel with the responsibility and authority to implement realtime actions to ensure the stable and reliable operation of the Generation Facility and Generation
Interconnection Facility, and the responsibility and authority to follow the directives of reliability
authorities including the Transmission Operator and Balancing Authority.” To PER-002-0, the Ad Hoc
Group proposed adding the Generator Operator to R1 (“Each Transmission Operator, Generator
Operator, and Balancing Authority shall be staffed with adequately trained operating personnel”) and
adding a new R3 that would read: “Each Generator Operator shall implement an initial and continuing
training program for all operating personnel that are responsible for operating the Generator
Interconnection Facility that verifies the personnel’s ability and understanding to operate the
equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.".”
Project 2010-07 Technical Justification Document
10
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changechanges to PER-002-0 and Order 742. Generator
Operators who deal with interconnection facilitiesFacilities at individual generating plants, on the other
hand, typically do not receive reliability-based orders specific to the interconnection Facilities and are
therefore not covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1
R3 already requires Generator Operators are, under currently approved reliability standards, required
to follow the directives issued by a Balancing Authority, Reliability Coordinator orof the appropriate
Transmission Operator. Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work untilunless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
Transm ission Operations (TOP) Standards
For TOP standards, the Ad Hoc Group proposed a number of new requirements that the SDT does not
see as supportive of reliability. This set of standards was somewhat difficult to analyze, as the Project
2007-03—Real-time Transmission Operations drafting team has made significant changes to TOP-001
through TOP-008, resulting in three proposed TOP standards where are currently eight (see the
project’s Implementation Plan). The Project 2010-07 reviewed both the FERC-approved TOP standards
and the fifth draft of the modified standards in Project 2007-03 to determine whether it needed to
propose any additional changes to cover radial generator interconnection Facilities. In addition, the
Project 2010-07 SDT contacted the Project 2010-07 to get its opinion as to whether there might be any
reliability gaps related to generator interconnection facilities. No such changes will be proposed for the
reasons outlined below.
The Ad Hoc Group proposed adding two new requirements to The FERC Order does not address PER001-0 or PER-002-0, but it does address PER-003-1. In paragraphs 67 and 81 of the FERC Order, FERC
expresses concern that operational control over the transmission line breakers owned by the entities
in question are not under the control of NERC certified operators. FERC goes on to say that “Reliability
Standard PER-003-001 requires NERC certification of all operators that have responsibility for the realtime operation of the interconnected Bulk Electric System. When switching the tie-line in or out of
service, operators must have the appropriate credentials and training to properly perform the
switching and coordinate the switching to prevent adverse impacts such as the introduction of faults
on the system.”
Project 2010-07 Technical Justification Document
11
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Project 2010-07 Technical Justification Document
12
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that this change is necessary.TOP-001-1 needs to
apply to Generator Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP003-2, as outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator
to coordinate its current-day, next-day, and seasonal operations with its Host Balancing Authority and
Transmission Service Provider. These entities are, in turn, required to coordinate with their respective
Project 2010-07 Technical Justification Document
13
Transmission Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-0032, as outlined in Project 2007-03’s Implementation Plan) requires each Balancing Authority and
Transmission Operator to coordinate with neighboring Balancing Authorities and Transmission
Operators and with its Reliability Coordinator. With these requirements, Generator Operators are
already required to provide necessary operations information to Transmission Operators. To require
the same thing in TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Project 2010-07 Technical Justification Document
14
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group alsohad proposed a new requirement, R7, for TOP-004-2—Transmission Operations
that would read: “The Generator Operator shall operate its Generator Interconnection Facility within
its applicable ratings.” The SDT does not agree that a reliability gap exists, because an operator has a
fiduciary obligation to protect a Facility for which it is operationally responsible. FAC-008-1—Facility
Ratings Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that
the reason for establishing a ratings methodology and communicating facility ratingsFacility Ratings to
the Reliability Coordinator, Planning Authority, Transmission Planner, and Transmission Operator is
“…for use in reliable planning and operation of the Bulk Electric System.” Further, TOP-004-2 is
proposed to be retired under the work of the Project 2007-03 drafting team. Its requirements will
either be deleted or assigned elsewhere.
The Ad Hoc team proposed to addTOP-006-1—Monitoring System Conditions (addressed in the NERC
Directive; the SDT believes NERC intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Project 2010-07 Technical Justification Document
15
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
deletingdelete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
radialsole-use interconnection Facilities. The changes to FAC-001 and, FAC-003 (, and now PRC-004)
have been supported by stakeholders during comment periods, and there has been no strong support
of technical justification provided for bringing other standards into the scope of this project.
That said, the SDT recognizes the success of its work depends on stakeholders, NERC, and FERC
agreeing that generator requirements at the transmission interface are covered under NERC Reliability
Standards, both for the sake of reliability and to prevent further unwarranted registration of Generator
Owners and Generator Operators as Transmission Owners and Transmission Operators. If the SDT’s
work does not close the gap in the eyes of all parties, that work will have been unsuccessful, so the SDT
is considering all feedback it receives with request to this project. While it is posting changes to only
FAC-001, FAC-003, and PRC-004, and stands by that decision, it will continue to consider whether
glossary term additions/modifications and modifications to other standards could enhance the
reliability impact of this project. Based on conversations with NERC and FERC staff, and review of
FERC’s Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind
Corridor Phase I (135 FERC ¶ 61,241), the SDT is discussing whether it should consider the following
requirements for further review: EOP-005-1 R1, R2, R6, R7; FAC-014-2 R2; PER-003-1 R1, R1.1, R1.2;
PRC-001-1 R2, R2.2, R4, R6; PRC-004-1 R1; TOP-001 R1; TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4; and TOP006-1 R3. The SDT is actively seeking stakeholder feedback as to whether, in light of these orders, it
should consider additional standards and or new or modifications to existing definitions as it proceeds
with its work.
Project 2010-07 Technical Justification Document
16
Technical Justification: FAC-001-1
Project 2010-07 Generator Requirements at the Transmission Interface
In response to the June 17-July 17, 2011 formal posting of the proposed standard changes in Project
2010-07, the standard drafting team (SDT) received stakeholder comments on FAC-001-1 expressing
concern about the feasibility of a Generator Owner receiving and executing an interconnection request
on one of its interconnection Facilities, as well as concern about the market-related processes that
would go along with such an interconnection request. In this technical justification document, the SDT
seeks to further clarify its rationale for making the proposed FAC-001-1 applicable to qualifying
Generator Owners.
While the SDT understands that interconnection requests for Generator Owner Facilities are still
relatively rare, in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their
Facilities. The SDT acknowledges that FERC does not have jurisdiction over all Generator Owners, but
realizes that the potential exists for a third party to request to interconnect its planned generator with
an existing generator interconnection Facility (whose use at the time of the request is solely to
transmit capacity, energy, and ancillary services from the existing generator).
The SDT discussed the various ways such an interconnection could occur and agrees that if the third
party interconnection could be accomplished without the need for the existing Generator Owner to
develop its own connection requirements and system performance requirements and determine
impacts on the interconnected transmission systems, this standard need not apply to the Generator
Owner. And the SDT agrees that in many cases, these connection requirements, system performance
requirements, and determined impacts on the interconnected transmission systems are currently
determined by entities registered as either a Transmission Owner, Transmission Planner, and/or
Transmission Service Provider. However, the SDT remains convinced (based on the orders cited above)
that there may be occasions where FERC or another regulatory agency compels the Generator Owner
to allow a third party to interconnect its planned generator with an existing generator interconnection
Facility. Where this occurs, the SDT feels it is necessary for the existing owner of that generator
interconnection Facility to provide connection requirements to the third party that requests
interconnection. The SDT also believes, and many comments seem to support, that performance
requirements and a determination of impact to the interconnected transmission systems need to be
evaluated by some entity. The question becomes which entity.
The SDT can only work within the standards development process. We cannot address other regulatory
issues such as FERC-mandated open transmission access (Order 888 and subsequent) or state or
provincial jurisdiction over generation or transmission assets. While we acknowledge these
mechanisms exists and may come into play in the scenarios described in the proposed FAC-001-1, we
as the SDT can only deal within the context of reliability standards. For this reason, R2 indicates that
FAC-001-1 applies only when a Generator Owner has an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility.
The SDT’s reasoning here is that if the owner of the existing generator interconnection Facility agrees,
or is compelled, to allow a third party to interconnect, and can do so using existing agreements,
contracts, and/or tariffs (and thereby avoid having an executed Agreement to evaluate the reliability
impact of interconnecting third party Facility to the Generator Owner’s existing Facility), and thus avoid
having to develop its own connection requirements or perform impact studies, it will. In this example,
it is likely that the existing Transmission Owner, Transmission Planner, and/or Transmission Service
Provider processes and Agreements will be utilized and the purpose of FAC-001-1 will be met without
applying this standard to the Generator Owner.
If, on the other hand, the owner of the existing generator interconnection Facility agrees, or is
compelled, to allow a third party to interconnect, but cannot do so without having to develop its own
connection requirements or perform impact studies, the SDT believes that the potential for a reliability
gap exists. This might occur, for instance, if the owner of an existing generator interconnection Facility
was compelled to allow interconnection and to implement open transmission access. In this example,
(under FERC Order 888 and subsequent orders), the existing interconnection owner becomes a
Transmission Service Provider and is required to have an Open Access Transmission Tariff (OATT).
FERC’s pro forma OATT requires the Transmission Service Provider to, among other things, perform
system impact and feasibility studies. In order to do so, such studies must be coordinated with other
Transmission Service Providers and Transmission Planners. And, to further complicate the issue, the
SDT has been informed that in Texas, a Generator Owner is not allowed to own transmission.
Clearly, these issues are complex and not all are within the jurisdiction of federal or provincial
regulators. For these reasons, the SDT took the only approach it found workable. If, and only if, the
existing owner of a generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply. The SDT believes that this is most likely to occur if the owner of an existing
generator interconnection Facility is compelled to allow a third party to interconnect and adopt open
transmission access. However, the SDT cannot be certain this is the only example and it therefore
proposes to add this new requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third party to interconnect,
have the necessary expertise to conduct the required interconnect studies to meet this standard.
However, the SDT believes that, upon executing such Agreement, the Generator Owner will have to
acquire such expertise. How the Generator Owner chooses to do so is not for the SDT to determine.
The SDT is tasked with identifying potential reliability gaps and addressing such gaps through the
standards development process.
Project 2010-07 Technical Justification for FAC-001-1
2
The SDT does agree with many comments asking that the Generator Owner not be required to
maintain its connection requirements, and there was robust discussion among the team and observers.
Some were concerned that, without an obligation to maintain, there would not be a review to ensure
compliance with NERC Reliability Standards and applicable Regional Entity, subregional, Power Pool,
and individual Transmission Owner planning criteria. Others were concerned that the third party
requesting interconnection might not actually interconnect, but the owner of the existing generator
interconnection Facility would, having executed an evaluation agreement, be forever obligated to
maintain connection requirements. In the end, the SDT agreed that if the owner of the existing
generator interconnection Facility adopted open access or was determined to be providing
“transmission service” it was likely that its existing registration would be re-evaluated and that the
issue would be more appropriately addressed at that time. The SDT has therefore agreed to remove
maintenance requirements for Generator Owners from both Requirement R2 and Requirement R4 in
the proposed FAC-001-1.
We hope that you have found this explanation of our rationale helpful, but if you have further
suggestions for improvement or clarity, please submit them in your comments on this latest posting.
Project 2010-07 Technical Justification for FAC-001-1
3
Standards Announcement
Project 2010-07
Generator Requirements at the Transmission Interface
Four Recirculation Ballots Window Open: December 14-23, 2011
Now Available
Recirculation ballot windows are open for the four standards listed below from Wednesday, December
14, 2011 through 8 p.m. Eastern on Friday, December 23, 2011.
•
FAC-001-1 – Facility Connection Requirements
•
Two versions of FAC-003 – Transmission Vegetation Management (FAC-003-3 and FAC-003X). Note that FAC-003-X shows changes to FAC-003-1, while FAC-003-3 shows changes to
FAC-003-2, which was developed by the Project 2007-07 standard drafting team.
•
Minor modifications to PRC-004-2.1 – Analysis and Mitigation of Transmission and
Generation Protection System Misoperations
Since the initial ballot, the drafting team has considered all comments received during the formal
comment period and initial ballots of the standards. Based on stakeholder comments, the SDT made
minor changes to FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1.
•
In FAC-001-1, the SDT corrected a typo in the Applicability section 4.2.1 to change “within”
to “with”; corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were
referenced, rather than just 3.1.1 through 3.1.6; and changed references to “Transmission
System” to “interconnected Transmission systems” to ensure consistency with the language
elsewhere in the standard and in FAC-002-1.
•
In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO
exemption in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and
changed “RE” to “Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements
at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either
(1) staffed and the overhead portion is within line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting these Facilities because
incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and appropriate risk prevention
approach.
To clarify the exemption, the SDT has modified the Applicability section 4.3.1 to include an explicit
reference to line of sight: “Overhead transmission lines that extend greater than one mile (1.609
kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has
been agreed upon by the stakeholder body. In its Consideration of Comments report from the last
formal comment period, which ended on July 17, 2011, the SDT explained, “We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the part
of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference here, the
SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Members of the ballot pool should note that the SDT is balloting both FAC-003-3 and FAC-003-X, but
stakeholders should not vote as though they are choosing one or the other. The SDT plans to present
FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X ready to submit to the
Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by FERC. Members of the
ballot body should vote on the merits of each version of FAC-003 individually. In other words,
stakeholders who support adding Generator Owners to the applicability of FAC-003 should vote in the
affirmative for both FAC-003-3 and FAC-003-X.
•
In PRC-004-2.1, the SDT added a reference to the generator interconnection Facility to the
data retention section of the standard (for consistency with the language in R2) and
corrected a typo in the Version History.
Additionally, many commenters encouraged the SDT to reexamine the standards and requirements
addressed in FERC’s Milford and Cedar Creek orders and NERC staff’s draft compliance directive
regarding generator lead lines. The SDT reviewed all addressed standards and requirements again and
continues to find clear and technical reliability-based reasons that support not adding Generator
Owner and Generator Operator requirements to these standards and not requiring the Generator
Owner or Generator Operator to register as a Transmission Owner or Transmission Operator.
However, to address stakeholder concern, the SDT has expanded its technical justification document
(posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Documents associated with this project, including clean and redline versions of each standard,
implementation plans for each standard (clean only since the SDT made no changes since the last
posting), the drafting team’s consideration of comments submitted during the parallel formal comment
Standards Announcement: Project 2010-07
Generator Requirements at the Transmission Interface
2
period and initial ballot that ended on November 18, 2011, and supporting materials including two
explanatory diagrams and the team’s updated technical justification, have been posted on the project
page.
Instructions for Balloting in the Recirculation Ballots
In a recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast a
ballot; all ballot pool members may change their prior votes. A ballot pool member who failed to cast a
ballot during the last ballot window may cast a ballot in the recirculation ballot window. If a ballot pool
member does not participate in the recirculation ballot, that member’s last vote cast in the successive
ballot that ended on November 18, 2011 will be carried over.
Members of the ballot pool associated with the project may log in and submit their votes in the
recirculation ballots from the following page: https://standards.nerc.net/CurrentBallots.aspx
Next Steps
If the standards achieve ballot pool approval, they will be presented to the Board of Trustees for
adoption.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often sole-use Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The SDT’s goal is to ensure that an adequate level of reliability is maintained in the BES by clearly
describing which standards need to be applied to generator interconnection Facilities that are not
already applicable to Generator Owners or Generator Operators. This can be accomplished by properly
applying FAC-001, FAC-003, PRC-004, and later, PRC-005, to Generator Owners as proposed in the
redline standards posted for ballot.
Standards Announcement: Project 2010-07
Generator Requirements at the Transmission Interface
3
Before reviewing the standards, the SDT encourages all stakeholders to read the technical justification
resource document posted under “Supporting Materials.” This document describes, in great detail, the
SDT’s rationale for its work thus far. Additional information is available on the project page at
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2010-07
Generator Requirements at the Transmission Interface
4
Standards Announcement
Project 2010-07
Generator Requirements at the Transmission Interface
Recirculation Ballot Results
Now Available
Recirculation ballots for the four standards listed below concluded on December 23, 2011.
•
FAC-001-1 – Facility Connection Requirements
•
Two versions of FAC-003 – Transmission Vegetation Management (FAC-003-3 and FAC-003-X).
Note that FAC-003-X shows changes to FAC-003-1, while FAC-003-3 shows changes to FAC-0032, which was developed by the Project 2007-07 standard drafting team.
•
Minor modifications to PRC-004-2.1 – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
Voting statistics for each ballot are listed in the table below, and the Ballot Results Webpage provides a
link to the detailed results.
Standard
Quorum
Approval
FAC-001-1
88.48%
90.10%
FAC-003-3
87.17%
85.38%
FAC-003-X
86.91%
85.03%
PRC-004-2.1a
86.65%
96.43%
Next Steps
Non-binding polls of the modified VRFs and VSLs will be conducted, and the standards, associated
implementation plans, and VRFs and VSLs will be presented to the NERC Board of Trustees for action. If
adopted, the standards will be filed with regulatory authorities.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often sole-use Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The SDT’s goal is to ensure that an adequate level of reliability is maintained in the BES by clearly
describing which standards need to be applied to generator interconnection Facilities that are not
already applicable to Generator Owners or Generator Operators. This can be accomplished by properly
applying FAC-001, FAC-003, PRC-004, and later, PRC-005, to Generator Owners as proposed in the
redline standards posted for ballot.
Before reviewing the standards, the SDT encourages all stakeholders to read the technical justification
resource document posted under “Supporting Materials.” This document describes, in great detail, the
SDT’s rationale for its work thus far. Additional information is available on the project page at
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2010-07
Ballot Results
2
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010-07_FAC-001-1 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 338
Register
Total Ballot Pool: 382
Quorum: 88.48 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
90.10 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.2
0.8
7
#
Votes
Fraction
68
5
48
23
66
34
0
5
1
7
257
Negative
Fraction
0.919
0.5
0.828
0.958
0.93
0.872
0
0.5
0.1
0.7
6.307
Abstain
No
# Votes Vote
6
0
10
1
5
5
0
0
1
1
29
0.081
0
0.172
0.042
0.07
0.128
0
0
0.1
0.1
0.693
10
2
13
4
11
9
0
0
2
1
52
11
2
9
3
12
3
1
2
1
0
44
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
View
View
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Abstain
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
View
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
View
View
View
View
View
View
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NERC Standards
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
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https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
NERC Standards
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-X_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 332
Register
Total Ballot Pool: 382
Quorum: 86.91 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.03 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.3
0.8
7
#
Votes
Fraction
62
4
47
17
57
32
0
3
3
6
231
Negative
Fraction
0.899
0.4
0.839
0.895
0.877
0.842
0
0.3
0.3
0.6
5.952
Abstain
No
# Votes Vote
7
1
9
2
8
6
0
1
0
2
36
0.101
0.1
0.161
0.105
0.123
0.158
0
0.1
0
0.2
1.048
14
2
15
7
14
10
0
1
1
1
65
12
2
9
5
15
3
1
2
1
0
50
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Negative
View
Abstain
Affirmative
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Abstain
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
Affirmative
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
View
Affirmative
Affirmative
Abstain
Negative
Donald Nelson
View
View
View
View
View
NERC Standards
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
NERC Standards
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-3 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 333
Register
Total Ballot Pool: 382
Quorum: 87.17 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.38 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.3
0.9
7.1
#
Votes
Fraction
63
5
49
18
59
33
0
3
3
6
239
Negative
Fraction
0.875
0.5
0.86
0.9
0.881
0.846
0
0.3
0.3
0.6
6.062
Abstain
No
# Votes Vote
9
0
8
2
8
6
0
1
0
3
37
0.125
0
0.14
0.1
0.119
0.154
0
0.1
0
0.3
1.038
12
2
14
6
12
9
0
1
1
0
57
11
2
9
5
15
3
1
2
1
0
49
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
Affirmative
View
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Negative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Negative
View
View
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Negative
Abstain
Affirmative
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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NERC Standards
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User Name
Ballot Results
Ballot Name: Project 2010-07 PRC-004-2.1 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 331
Register
Total Ballot Pool: 382
Quorum: 86.65 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
96.43 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.3
0.9
7.2
#
Votes
Fraction
67
5
55
22
65
37
0
5
3
9
268
Negative
Fraction
0.957
0.5
0.948
0.957
0.956
0.925
0
0.5
0.3
0.9
6.943
Abstain
No
# Votes Vote
3
0
3
1
3
3
0
0
0
0
13
0.043
0
0.052
0.043
0.044
0.075
0
0
0
0
0.257
13
2
12
4
10
8
0
0
1
0
50
12
2
10
4
16
3
1
2
1
0
51
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Ballot
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Abstain
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Abstain
Affirmative
Affirmative
Affirmative
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Affirmative
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Affirmative
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Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Abstain
Affirmative
Affirmative
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Affirmative
Abstain
Affirmative
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Affirmative
Affirmative
Affirmative
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
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View
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NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
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Affirmative
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Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
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Affirmative
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Affirmative
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Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
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Affirmative
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View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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Affirmative
Affirmative
Donald Nelson
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NERC Standards
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Ballot Results
Ballot Name: Project 2010-07_FAC-001-1 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 338
Register
Total Ballot Pool: 382
Quorum: 88.48 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
90.10 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.2
0.8
7
#
Votes
Fraction
68
5
48
23
66
34
0
5
1
7
257
Negative
Fraction
0.919
0.5
0.828
0.958
0.93
0.872
0
0.5
0.1
0.7
6.307
Abstain
No
# Votes Vote
6
0
10
1
5
5
0
0
1
1
29
0.081
0
0.172
0.042
0.07
0.128
0
0
0.1
0.1
0.693
10
2
13
4
11
9
0
0
2
1
52
11
2
9
3
12
3
1
2
1
0
44
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Abstain
Comments
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
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View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
View
View
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Abstain
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
View
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
View
View
View
View
View
View
View
NERC Standards
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A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=37ec40ef-a35d-4e77-835e-c37b1723a21a[12/27/2011 12:44:18 PM]
NERC Standards
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-X_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 332
Register
Total Ballot Pool: 382
Quorum: 86.91 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.03 %
Vote:
Ballot Results: The Standard has Passed (Note: These ballot results have been voided.)
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.3
0.8
7
#
Votes
Fraction
62
4
47
17
57
32
0
3
3
6
231
Negative
Fraction
0.899
0.4
0.839
0.895
0.877
0.842
0
0.3
0.3
0.6
5.952
Abstain
No
# Votes Vote
7
1
9
2
8
6
0
1
0
2
36
0.101
0.1
0.161
0.105
0.123
0.158
0
0.1
0
0.2
1.048
14
2
15
7
14
10
0
1
1
1
65
12
2
9
5
15
3
1
2
1
0
50
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Negative
View
Abstain
Affirmative
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Abstain
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a903c605-08e4-4f1f-b14e-6d620a7b7b9a[12/27/2011 12:47:21 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
View
Affirmative
Affirmative
Abstain
Negative
Affirmative
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NERC Standards
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Ballot Results
Ballot Name: Project 2010-07 FAC-003-3 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 333
Register
Total Ballot Pool: 382
Quorum: 87.17 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.38 %
Vote:
Ballot Results: The Standard has Passed (Note: These ballot results have been voided.)
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.4
0.3
0.9
7.1
#
Votes
Fraction
63
5
49
18
59
33
0
3
3
6
239
Negative
Fraction
0.875
0.5
0.86
0.9
0.881
0.846
0
0.3
0.3
0.6
6.062
Abstain
No
# Votes Vote
9
0
8
2
8
6
0
1
0
3
37
0.125
0
0.14
0.1
0.119
0.154
0
0.1
0
0.3
1.038
12
2
14
6
12
9
0
1
1
0
57
11
2
9
5
15
3
1
2
1
0
49
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
Affirmative
View
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Negative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Negative
View
View
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
Negative
Abstain
Affirmative
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
View
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d34ae8b4-ad64-4a54-a9cc-c412d3f1aa8e[12/27/2011 12:45:24 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Frank R. McElvain
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
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Ballot Results
Ballot Name: Project 2010-07 PRC-004-2.1 Initial Ballot_rc
Password
Ballot Period: 12/14/2011 - 12/23/2011
Log in
Ballot Type: recirculation
Total # Votes: 331
Register
Total Ballot Pool: 382
Quorum: 86.65 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
96.43 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.5
1
1
1
1
0
0.5
0.3
0.9
7.2
#
Votes
Fraction
67
5
55
22
65
37
0
5
3
9
268
Negative
Fraction
0.957
0.5
0.948
0.957
0.956
0.925
0
0.5
0.3
0.9
6.943
Abstain
No
# Votes Vote
3
0
3
1
3
3
0
0
0
0
13
0.043
0
0.052
0.043
0.044
0.075
0
0
0
0
0.257
13
2
12
4
10
8
0
0
1
0
50
12
2
10
4
16
3
1
2
1
0
51
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Ballot
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Abstain
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
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Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
View
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Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
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NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
View
Affirmative
Abstain
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Max Emrick
Affirmative
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Affirmative
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2f0ec2d5-5712-4139-98e5-51bc465dcb78[12/27/2011 1:02:56 PM]
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
View
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View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
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Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
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of Public Utilities
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S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Draft 3: December 1, 2011
1 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission systems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 3: December 1, 2011
2 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission systems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 3: December 1, 2011
3 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 3: December 1, 2011
4 of 5
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Draft 3: December 1, 2011
5 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Draft 3: December 1, 2011
1 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission systems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 3: December 1, 2011
2 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission systems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 3: December 1, 2011
3 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
High VSL
The Transmission
Owner failed to do one
of the following:
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish its facility
connection
requirements as
specified in the
Requirement.
Document or maintain
or publish
facilityFacility
connection
requirements as
specified in the
Requirement
OR
Failed to include one
(1) of the components
andas specified in
R1.1, R1.2 or R1.3.
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
Draft 3: December 1, 2011
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
4 of 6
Severe VSL
The Transmission
Owner did not
develop
facilityFacility
connection
requirements.
OR
Failed to include (2) of
the components as
specified in R1.1, R1.2
or R1.3
OR
Failed to document or
maintain or publish its
facilityFacility
connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
(a)
The
Generator Owner
failed to document
and publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The Transmission
Owner’s
facilityresponsible
entity’s Facility
connection
requirements failed to
address one of the subrequirements.
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
The Transmission
Owner’s
facilityresponsible
entity’s Facility
connection
requirements failed to
address two of the subrequirements.
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
The Transmission
Owner’s
facilityresponsible
entity’s Facility
connection
requirements failed to
address three of the
sub-requirements.
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The Transmission
Owner’s
facilityresponsible
entity’s Facility
connection
requirements failed
to address four or
more of the subrequirements. parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
OR
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The Transmission
Owner does not
have facility
connection
requirements.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
Revision under Project
2010-07
Draft 3: December 1, 2011
5 of 6
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
date.
Draft 3: December 1, 2011
6 of 6
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FAC001-1
R1
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO). Because the drafting
team made no changes to R1, the
team determined that any further
changes to R1’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors.. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
FAC001-1
R2
The VSLs for R2 are written in
accordance with NERC’s VSL
Guideline’s formatting
recommendations. The
requirement is not of the pass/fail
variety, so the VSL assignments
have been gradated based on
when the Generator Owner
documented and published the
Facility connection requirements.
As is recommended by NERC’s VSL
Guidelines, the drafting team
Because this is a new requirement,
there is no current level of
compliance with which the VSL
assignments can be compared.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. The
VSL assignments are consistent
with the requirement and the
degree of compliance can be
determined objectively and with
certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
The proposed text is clear, specific,
and does not contain general,
relative or subjective language
(and is not subject to the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. After
modifying “Transmission Owner”
to “responsibility entity”, the VSL
assignments are consistent with
the requirement and the degree of
compliance can be determined
objectively and with certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
identified a reasonable delay for
the Lower VSL and then used 10day increments to develop the
Moderate, High, and Severe VSLs.
FAC001-1
R3
For its proposed changes to VSLs
for FAC-001-1 R3, the drafting
team used the FERC-approved
VSLs (then FAC-001-0 R2) in 135
FERC ¶ 61,166 as a starting point.
The VSLs were already
appropriately gradated with
penalties based on the
recommendation for requirements
with parts that contribute equally
to the requirement, and removing
the second half of R3’s Severe VSL
simply avoids any double jeopardy
compliance issues, as indicated in
the Guideline 2 explanation.
possibility of multiple
interpretations), satisfying
Guideline 2b.
The drafting team’s slight
modification to the Severe VSL for
R3 does not signal a lower
compliance threshold than
previously existed.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team determined that
the second half of the Severe VSL
in R3 (“The responsible entity does
not have Facility connection
requirements”) could lead to
double jeopardy because of its
redundancy with the Severe VSLs
in R1 (“The Transmission Owner
did not develop Facility connection
requirements”) and R2 (“The
Generator Owner failed to
document and publish and
thereafter maintain Facility
connection requirements until
more than 80 days…”). Thus, the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
second half of the VSL for R3 has
been deleted.
With this change, the text is clear,
specific, and does not contain
general, relative or subjective
language (and is not subject to the
possibility of multiple
interpretations), satisfying
Guideline 2b.
FAC001-1
R4
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because, with this
posting, the drafting team made
no changes to R4 compared to the
FERC approved version (then R3),
the team determined that any
further changes to R4’s VSLs would
be outside of the scope of Project
2010-07.
VRFs for FAC-001-1:
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
The VRFs for FAC-001-1 were transferred from NERC’s VRF Matrix – which includes VRFs that have already been approved by FERC – to bring the
formatting of the standard up to date. A Medium VRF was added to new Requirement R2, which applies to Generator Owners, to match the
Medium VRF for the comparable Requirement R1, which applies to Transmission Owners.
Implementation Plan for FAC-001-1—Facility
Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired at midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify one existing requirement (now R3)). Therefore, this implementation plan only
identifies a compliance timeframe for Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Standards Announcement
Project 2010-07
Generator Requirements at the Transmission Interface
Non-Binding Poll January 4 – 13, 2012
Now Available
Over the last year, the Project 2010-07 Generator Requirements at the Transmission Interface SDT has
proposed and vetted changes to FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1. All four standards
were approved by their respective ballot pools in recirculation ballots that ended on December 23, 2011.
FAC-001, FAC-003-3, and PRC-004-2.1a (which includes the interpretation from PRC-004-2a) will be
presented to the NERC Board of Trustees for approval in February 2012.
From January 4-13, 2012, the SDT will be conducting a non-binding poll of the VSLs and VRFs that were
substantively revised. FAC-003-X’s and PRC-004-2.1a’s VSLs and VRFs were not revised at all and FAC-0033’s VSLs and VRFs were only edited to change the responsible entity in the VSLs, so only FAC-001-1’s VSLs
and VRFs are being posted for the non-binding poll.
Detail on Updates to VSLs and VRFs for FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1a
Because it was a Version 0 standard, FAC-001-0 did not initially have VSLs or VRFs assigned to it. The VSLs
for FAC-001-1 were transferred from the VSLs filed by NERC staff on March 21, 2011 (in Supplemental
Information to the NERC Compliance Filing in Response to the Order on Violation Severity Levels Proposed
by the ERO). The VRFs for FAC-001-1 were transferred into the standard from NERC’s VRF Matrix – which
includes VRFs that have already been approved by FERC – to bring the format of the standard up to date.
For existing Requirements R1 and R4 (applicable to Transmission Owners only), no substantive changes to
VSLs or VRFs were made, although typographical errors in the VSLs for R1 was corrected. For new
requirement R2 (applicable to Generator Owners only), the Project 2010-07 standard drafting team applied
the comparable VRF from R1 and developed a set of VSLs according to NERC and FERC guidelines. For
modified Requirement R3 (applicable to Transmission Owners and Generator Owners), no substantive
changes to the VSLs or VRFs were made, although a typographical error in the VSLs for R3 was corrected
and “Transmission Owner” was changed to “responsible entity.”
The proposed changes in FAC-003-3 serve only to make the standard applicable to qualifying Generator
Owners, so no changes were proposed for the VRFs for FAC-003-3. The only modification proposed for the
VSLs for FAC-003-3 was to change all references to “Transmission Owner” to “responsible entity.”
The proposed change in PRC-004-2.1a Requirement R2 is a clarifying (errata) change that makes clear that
generator interconnection Facilities are also part of Generator Owners’ responsibility in the context of this
standard. Thus, no changes were proposed for the VRFs or VSLs for PRC-004-2.1a.
Instructions for Casting an Opinion in the Non-binding Poll
Members of the ballot pool associated with this project may log in and submit their opinion for the nonbinding polls from the following page: https://standards.nerc.net/CurrentBallots.aspx
Next Steps
FAC-001, FAC-003-3, and PRC-004-2.1a will be presented to the NERC Board of Trustees for adoption in
February 2012, and information on the non-binding poll results will be provided to the Board for
consideration in their decision.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately covered
under NERC’s Reliability Standards. While many Generator Owners and Generator Operators operate
Facilities, commonly known as generator interconnection Facilities, that are considered by some entities to
be transmission, these are most often sole-use Facilities that are not part of the integrated grid. As such,
they should not be subject to the same standards applicable to Transmission Owners and Transmission
Operators who own and operate Transmission Elements and Facilities that are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator Owner
or Generator Operator as a Transmission Owner or Transmission Operator, as has been the solution in some
cases in the past, may decrease reliability by diverting the Generator Owner’s or Generator Operator’s
resources from the operation of the equipment that actually produces electricity – the generation
equipment itself.
The SDT’s goal is to ensure that an adequate level of reliability is maintained in the BES by clearly describing
which standards need to be applied to generator interconnection Facilities that are not already applicable
to Generator Owners or Generator Operators. This can be accomplished by properly applying FAC-001,
FAC-003, PRC-004, and later, PRC-005, to Generator Owners. Additional information is available on the
project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2010-07
Generator Requirements at the Transmission Interface
2
Standards Announcement: Project 2010-07
Generator Requirements at the Transmission Interface
3
Update
Non-binding Poll Results
Project 2010-07 Generator Requirements at the Transmission Interface
Ballot Results
Non-binding Poll
Project 2010-07 GOTO non-binding poll FAC-001-1
Name:
Poll Period: 1/4/2012 - 1/13/2012
Total # Opinions: 208
Total Ballot Pool: 382
78.27% of those who registered to participate provided an opinion
Summary Results: or abstention. 93% of those who provided an opinion indicated
support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company,
LLC
Arizona Public Service Co.
Associated Electric Cooperative,
Inc.
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
CenterPoint Energy Houston
Electric, LLC
Central Maine Power Company
City of Tacoma, Department of
Public Utilities, Light Division, dba
Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New
York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Project 2010-07 Non-binding Poll Results
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Ballot
Comments
Affirmative
Abstain
Abstain
Robert Smith
John Bussman
Affirmative
Scott J Kinney
Kevin Smith
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Abstain
Abstain
Affirmative
Affirmative
Tony Kroskey
John Brockhan
Abstain
Kevin L Howes
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative
Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission
Company Holdings Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
1
Pacific Gas and Electric Company
1
1
1
1
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
1
1
1
1
1
1
1
1
1
1
1
Project 2010-07 Non-binding Poll Results
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Dennis Minton
Affirmative
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Affirmative
Bob Solomon
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Abstain
Affirmative
Affirmative
View
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore
Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
3
3
PowerSouth Energy Cooperative
Larry D Avery
PPL Electric Utilities Corp.
Brenda L Truhe
Progress Energy Carolinas
Brett A Koelsch
Public Service Company of New
Laurie Williams
Mexico
Public Service Electric and Gas Co. Kenneth D. Brown
Public Utility District No. 1 of
Dale Dunckel
Okanogan County
Puget Sound Energy, Inc.
Denise M Lietz
Rochester Gas and Electric Corp.
John C. Allen
Sacramento Municipal Utility District Tim Kelley
Salt River Project
Robert Kondziolka
San Diego Gas & Electric
Will Speer
Santee Cooper
Terry L Blackwell
SCE&G
Henry Delk, Jr.
Seattle City Light
Pawel Krupa
Sho-Me Power Electric Cooperative Denise Stevens
Sierra Pacific Power Co.
Rich Salgo
Snohomish County PUD No. 1
Long T Duong
South California Edison Company
Steven Mavis
Southern Company Services, Inc.
Robert Schaffeld
Southern Illinois Power Coop.
William Hutchison
Southwest Transmission
James Jones
Cooperative, Inc.
Tampa Electric Co.
Beth Young
Tennessee Valley Authority
Larry Akens
Tri-State G & T Association, Inc.
Tracy Sliman
Tucson Electric Power Co.
John Tolo
United Illuminating Co.
Jonathan Appelbaum
Vermont Electric Power Company,
Kim Moulton
Inc.
Westar Energy
Allen Klassen
Western Area Power Administration Brandy A Dunn
Xcel Energy, Inc.
Gregory L Pieper
Alberta Electric System Operator
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
Independent Electricity System
Barbara
Operator
Constantinescu
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System
Gregory Campoli
Operator
PJM Interconnection, L.L.C.
Tom Bowe
Southwest Power Pool, Inc.
Charles Yeung
AEP
Michael E Deloach
Alabama Power Company
Richard J. Mandes
Project 2010-07 Non-binding Poll Results
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Affirmative
View
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New
York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations
Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of
Georgia
Project 2010-07 Non-binding Poll Results
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Peter T Yost
Abstain
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
Abstain
William N. Phinney
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Steven M. Jackson
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
4
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
Muscatine Power & Water
John S Bos
Nebraska Public Power District
Tony Eddleman
New York Power Authority
Marilyn Brown
Niagara Mohawk (National Grid
Michael Schiavone
Company)
Northern Indiana Public Service Co. William SeDoris
NRG Energy Power Marketing, Inc. Rick Keetch
Ocala Electric Utility
David Anderson
Orange and Rockland Utilities, Inc. David Burke
Oregon Trail Electric Cooperative
ned ratterman
Orlando Utilities Commission
Ballard K Mutters
Owensboro Municipal Utilities
Thomas T Lyons
Pacific Gas and Electric Company
John H Hagen
PacifiCorp
Dan Zollner
Platte River Power Authority
Terry L Baker
PNM Resources
Michael Mertz
Potomac Electric Power Co.
Robert Reuter
Progress Energy Carolinas
Sam Waters
Public Service Electric and Gas Co. Jeffrey Mueller
Public Utility District No. 2 of Grant
Greg Lange
County
Puget Sound Energy, Inc.
Erin Apperson
Sacramento Municipal Utility District James Leigh-Kendall
Salt River Project
John T. Underhill
Santee Cooper
James M Poston
Seattle City Light
Dana Wheelock
Seminole Electric Cooperative, Inc. James R Frauen
Snohomish County PUD No. 1
Mark Oens
South Carolina Electric & Gas Co.
Hubert C Young
Tacoma Public Utilities
Travis Metcalfe
Tampa Electric Co.
Ronald L Donahey
Tennessee Valley Authority
Ian S Grant
Tri-State G & T Association, Inc.
Janelle Marriott
Westar Energy
Bo Jones
Wisconsin Electric Power Marketing James R Keller
Xcel Energy, Inc.
Michael Ibold
Alabama Municipal Electric
Raymond Phillips
Authority
Alliant Energy Corp. Services, Inc. Kenneth Goldsmith
American Municipal Power
Kevin Koloini
Blue Ridge Power Agency
Duane S Dahlquist
City of Clewiston
Kevin McCarthy
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri John Allen
Consumers Energy
David Frank Ronk
Cowlitz County PUD
Rick Syring
Detroit Edison Company
Daniel Herring
Project 2010-07 Non-binding Poll Results
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
5
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Thomas Richards
Georgia System Operations
Guy Andrews
Corporation
Imperial Irrigation District
Diana U Torres
Indiana Municipal Power Agency
Jack Alvey
Integrys Energy Group, Inc.
Christopher Plante
Madison Gas and Electric Co.
Joseph DePoorter
Modesto Irrigation District
Spencer Tacke
North Carolina Electric Membership
Bob Beadle
Corp.
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Old Dominion Electric Coop.
Mark Ringhausen
Public Utility District No. 1 of
Henry E. LuBean
Douglas County
Public Utility District No. 1 of
John D Martinsen
Snohomish County
Sacramento Municipal Utility District Mike Ramirez
Seattle City Light
Hao Li
Seminole Electric Cooperative, Inc. Steven R Wallace
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
AEP Service Corp.
Brock Ondayko
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
American Wind Energy Association Natalie McIntire
Arizona Public Service Co.
Edward Cambridge
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Black Hills Corp
George Tatar
Boise-Kuna Irrigation District/dba
Mike D Kukla
Lucky peak power plant project
Bonneville Power Administration
Francis J. Halpin
BP Wind Energy North America Inc Carla Bayer
BrightSource Energy, Inc.
Chifong Thomas
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul Cummings
City of Tacoma, Department of
Public Utilities, Light Division, dba Max Emrick
Tacoma Power
City of Tallahassee
Brian Horton
City Water, Light & Power of
Steve Rose
Springfield
Project 2010-07 Non-binding Poll Results
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
6
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New
York
Constellation Power Source
Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia
Generating Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and
Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
Project 2010-07 Non-binding Poll Results
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Affirmative
Affirmative
Affirmative
Abstain
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Abstain
Affirmative
Affirmative
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Abstain
Affirmative
James Sauceda
Kenneth B Parker
Michael Korchynsky
Abstain
Affirmative
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Kenneth Silver
Affirmative
Tom Foreman
Mike Laney
S N Fernando
Abstain
Affirmative
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Affirmative
Affirmative
Abstain
7
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
New York Power Authority
Gerald Mannarino
North Carolina Electric Membership
Jeffrey S Brame
Corp.
Northern California Power Agency
Hari Modi
Northern Indiana Public Service Co. William O. Thompson
Occidental Chemical
Michelle R DAntuono
Oklahoma Gas and Electric Co.
Kim Morphis
Omaha Public Power District
Mahmood Z. Safi
Ontario Power Generation Inc.
Colin Anderson
PacifiCorp
Sandra L. Shaffer
Platte River Power Authority
Roland Thiel
Portland General Electric Co.
Gary L Tingley
PPL Generation LLC
Annette M Bannon
Progress Energy Carolinas
Wayne Lewis
PSEG Fossil LLC
Mikhail Falkovich
Public Utility District No. 1 of Lewis
Steven Grega
County
Puget Sound Energy, Inc.
Tom Flynn
RES Americas Inc
Ravi Bantu
Sacramento Municipal Utility District Bethany Hunter
Salt River Project
William Alkema
Santee Cooper
Lewis P Pierce
Seattle City Light
Michael J. Haynes
Seminole Electric Cooperative, Inc. Brenda K. Atkins
Siemens PTI
Edwin Cano
Snohomish County PUD No. 1
Sam Nietfeld
South Carolina Electric & Gas Co.
Edward Magic
Southern California Edison Co.
Denise Yaffe
Southern Company Generation
William D Shultz
Tampa Electric Co.
RJames Rocha
Tenaska, Inc.
Scott M Helyer
Tennessee Valley Authority
David Thompson
Tri-State G & T Association, Inc.
Barry Ingold
U.S. Army Corps of Engineers
Melissa Kurtz
Wisconsin Electric Power Co.
Linda Horn
Wisconsin Public Service Corp.
Leonard Rentmeester
Xcel Energy, Inc.
Liam Noailles
ACES Power Marketing
Jason L Marshall
AEP Marketing
Edward P. Cox
Ameren Energy Marketing Co.
Jennifer Richardson
APS
RANDY A YOUNG
Bonneville Power Administration
Brenda S. Anderson
City of Austin dba Austin Energy
Lisa L Martin
City of Redding
Marvin Briggs
Cleco Power LLC
Robert Hirchak
Colorado Springs Utilities
Lisa C Rosintoski
Consolidated Edison Co. of New
Nickesha P Carrol
Project 2010-07 Non-binding Poll Results
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
View
View
8
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
York
Constellation Energy Commodities
Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L.
Florida Municipal Power Agency
Montgomery
Florida Municipal Power Pool
Thomas Washburn
Florida Power & Light Co.
Silvia P. Mitchell
Great River Energy
Donna Stephenson
Imperial Irrigation District
Cathy Bretz
Kansas City Power & Light Co.
Jessica L Klinghoffer
Lakeland Electric
Paul Shipps
Lincoln Electric System
Eric Ruskamp
Luminant Energy
Brad Jones
Manitoba Hydro
Daniel Prowse
MidAmerican Energy Co.
Dennis Kimm
New York Power Authority
William Palazzo
Northern Indiana Public Service Co. Joseph O'Brien
NRG Energy, Inc.
Alan Johnson
Claston Augustus
Orlando Utilities Commission
Sunanon
PacifiCorp
Scott L Smith
Platte River Power Authority
Carol Ballantine
PPL EnergyPlus LLC
Mark A Heimbach
Progress Energy
John T Sturgeon
PSEG Energy Resources & Trade
Peter Dolan
LLC
Public Utility District No. 1 of Chelan
Hugh A. Owen
County
Sacramento Municipal Utility District Diane Enderby
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown
Seattle City Light
Dennis Sismaet
Seminole Electric Cooperative, Inc. Trudy S. Novak
Snohomish County PUD No. 1
William T Moojen
South California Edison Company
Lujuanna Medina
Southern Company Generation and
John J. Ciza
Energy Marketing
Tacoma Public Utilities
Michael C Hill
Tampa Electric Co.
Benjamin F Smith II
Tennessee Valley Authority
Marjorie S. Parsons
Westar Energy
Grant L Wilkerson
Western Area Power Administration
Peter H Kinney
- UGP Marketing
Project 2010-07 Non-binding Poll Results
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
9
6
7
8
8
8
8
8
8
8
Xcel Energy, Inc.
Siemens Energy, Inc.
9
California Energy Commission
9
9
9
9
10
10
10
10
10
10
10
10
10
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory
Utility Commissioners
New York State Department of
Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating
Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating
Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating
Council
Project 2010-07 Non-binding Poll Results
David F. Lemmons
Frank R. McElvain
James A Maenner
Edward C Stein
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M
Chamberlain
Donald Nelson
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Diane J Barney
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Affirmative
Affirmative
Guy V. Zito
Affirmative
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Negative
Abstain
Affirmative
Affirmative
Steven L. Rueckert
Affirmative
View
10
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
A. Introduction
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish Facility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
B.
Requirements
R1. The Transmission Owner shall document, maintain, and publish Facility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Entity, subregional, Power Pool, and individual Transmission Owner planning criteria and
Facility connection requirements. The Transmission Owner’s Facility connection
requirements shall address connection requirements for:
1.1.
Generation Facilities,
1.2.
Transmission Facilities, and
1.3.
End-user Facilities
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
Draft 3: December 1, 2011
1 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
3.1. Provide a written summary of its plans to achieve the required system performance as
described in Requirements R1 or R2 throughout the planning horizon:
3.1.1. Procedures for coordinated joint studies of new Facilities and their impacts on the
interconnected Transmission systems.
3.1.2. Procedures for notification of new or modified Facilities to others (those
responsible for the reliability of the interconnected Transmission systems) as
soon as feasible.
3.1.3. Voltage level and MW and MVAR capacity or demand at point of connection.
3.1.4. Breaker duty and surge protection.
3.1.5. System protection and coordination.
3.1.6. Metering and telecommunications.
3.1.7. Grounding and safety issues.
3.1.8. Insulation and insulation coordination.
3.1.9. Voltage, Reactive Power, and power factor control.
3.1.10. Power quality impacts.
3.1.11. Equipment Ratings.
3.1.12. Synchronizing of Facilities.
3.1.13. Maintenance coordination.
3.1.14. Operational issues (abnormal frequency and voltages).
3.1.15. Inspection requirements for existing or new Facilities.
3.1.16. Communications and procedures during normal and emergency operating
conditions.
[VRF – Medium]
R4. The Transmission Owner shall maintain and update its Facility connection requirements as
required. The Transmission Owner shall make documentation of these requirements available
to the users of the transmission system, the Regional Entity, and ERO on request (five
business days).
[VRF – Medium]
C.
Measures
M1. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R1.
Draft 3: December 1, 2011
2 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
M2. Each Generator Owner that has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the interconnected Transmission systems shall make available (to its
Compliance Enforcement Authority) evidence that it met all requirements stated in
Requirement R2.
M3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Enforcement Authority) evidence
that it met all requirements stated in Requirement R3.
M4. The Transmission Owner shall make available (to its Compliance Enforcement Authority)
evidence that it met all the requirements stated in Requirement R4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor: Regional Entity
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
Draft 3: December 1, 2011
3 of 5
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
2.
Violation Severity Levels
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
High VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
Failed to document or
maintain or publish its
Facility connection
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
The responsible
entity’s Facility
connection
Failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
Draft 3: December 1, 2011
4 of 5
Severe VSL
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
S ta n d a rd FAC-001-1 — Fa c ility Co n n e c tio n Req u ire m e nts
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
E.
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Draft 3: December 1, 2011
5 of 5
S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
Introduction
B.A.
1.
Title:
Facility Connection Requirements
2.
Number:
FAC-001-0 1
3.
Purpose:
To avoid adverse impacts on reliability, Transmission Owners and Generator
Owners must establish facilityFacility connection and performance requirements.
4.
Applicability:
4.1. Transmission Owner
4.2. Applicable Generator Owner
4.2.1
5.
Generator Owner with an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing
Facility that is used to interconnect to the interconnected Transmission systems.
Effective Date:
April 1, 2005
5.1. In those jurisdictions where regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon regulatory approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to the
Transmission Owner and Regional Entity become effective upon Board of Trustees’
adoption.
5.2. In those jurisdictions where regulatory approval is required, all requirements applied to
the Generator Owner become effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities. In those jurisdictions where no regulatory approval is required, all
requirements applied to the Generator Owner become effective on the first calendar day
of the first calendar quarter one year after Board of Trustees’ adoption.
C.B. Requirements
R1. The Transmission Owner shall document, maintain, and publish facilityFacility connection
requirements to ensure compliance with NERC Reliability Standards and applicable Regional
Reliability OrganizationEntity, subregional, Power Pool, and individual Transmission Owner
planning criteria and facilityFacility connection requirements. The Transmission Owner’s
facilityFacility connection requirements shall address connection requirements for:
R1.1.1.1.
Generation facilities,Facilities,
R1.2.1.2.
Transmission facilitiesFacilities, and
R1.3.1.3.
End-user facilitiesFacilities
R2. The Transmission Owner’s facility connection requirements shall address, but are not limited
to, the following items:
[VRF – Medium]
R2. Each applicable Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the Generator
Owner’s existing Facility that is used to interconnect to the interconnected Transmission
systems (under FAC-002-1), document and publish its Facility connection requirements to
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
ensure compliance with NERC Reliability Standards and applicable Regional Entity,
subregional, Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.
[VRF – Medium]
R3. Each Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall address the following items in its Facility connection requirements:
R2.1.3.1.
Provide a written summary of its plans to achieve the required system
performance as described abovein Requirements R1 or R2 throughout the planning
horizon:
R2.1.1.3.1.1. Procedures for coordinated joint studies of new facilitiesFacilities and
their impacts on the interconnected transmissionTransmission systems.
R2.1.2.3.1.2. Procedures for notification of new or modified facilitiesFacilities to
others (those responsible for the reliability of the interconnected
transmissionTransmission systems) as soon as feasible.
R2.1.3.3.1.3. Voltage level and MW and MVAR capacity or demand at point of
connection.
R2.1.4.3.1.4.
Breaker duty and surge protection.
R2.1.5.3.1.5.
System protection and coordination.
R2.1.6.3.1.6.
Metering and telecommunications.
R2.1.7.3.1.7.
Grounding and safety issues.
R2.1.8.3.1.8.
Insulation and insulation coordination.
R2.1.9.3.1.9.
Voltage, Reactive Power, and power factor control.
R2.1.10.3.1.10. Power quality impacts.
R2.1.11.3.1.11. Equipment Ratings.
R2.1.12.3.1.12. Synchronizing of facilitiesFacilities.
R2.1.13.3.1.13. Maintenance coordination.
R2.1.14.3.1.14. Operational issues (abnormal frequency and voltages).
R2.1.15.3.1.15. Inspection requirements for existing or new facilitiesFacilities.
R2.1.16.3.1.16. Communications and procedures during normal and emergency
operating conditions.
[VRF – Medium]
R3.R4. The Transmission Owner shall maintain and update its facilityFacility connection
requirements as required. The Transmission Owner shall make documentation of these
requirements available to the users of the transmission system, the Regional Reliability
OrganizationEntity, and NERCERO on request (five business days).
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
[VRF – Medium]
D.C. Measures
M1. The Transmission Owner shall make available (to its Compliance Monitor) for
inspectionEnforcement Authority) evidence that it met all the requirements stated in
Reliability Standard FAC-001-0_Requirement R1.
M2. TheEach Generator Owner that has an executed Agreement to evaluate the reliability impact
of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used
to interconnect to the interconnected Transmission Ownersystems shall make available (to its
Compliance Monitor) for inspectionEnforcement Authority) evidence that it met all
requirements stated in Reliability Standard FAC-001-0_Requirement R2.
M3. TheEach Transmission Owner and each applicable Generator Owner (in accordance with
Requirement R2) shall make available (to its Compliance Monitor) for inspectionEnforcement
Authority) evidence that it met all the requirements stated in Reliability Standard FAC-0010_R3Requirement R3.
M3.M4. The Transmission Owner shall make available (to its Compliance Enforcement
Authority) evidence that it met all the requirements stated in Requirement R4.
E.D. Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
Compliance Monitor: Regional Reliability Organization.Entity
1.2.
Compliance Monitoring Period and Reset TimeframeEnforcement Processes:
On request (five business days).
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
None specified.
The Transmission Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,
Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last
audit.
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
The Generator Owner shall keep data or evidence to show compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and
Requirement R3, Measure M3 from its last audit.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels of Non-Compliance
2.1.
Level 1:
Facility connection requirements were provided for generation,
transmission, and end-user facilities, per Reliability Standard FAC-001-0_R1, but the
document(s) do not address all of the requirements of Reliability Standard FAC-0010_R2.
2.2.
Level 2:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, but the document(s) provided address all of the requirements of
Reliability Standard FAC-001-0_R2.
2.3.
Level 3:
Facility connection requirements were not provided for all three
categories (generation, transmission, or end-user) of facilities, per Reliability Standard
FAC-001-0_R1, and the document(s) provided do not address all of the requirements
of Reliability Standard FAC-001-0_R2.
2.4.
Level 4:
No document on facility connection requirements was provided per
Reliability Standard FAC-001-0_R3.
R
#
Lower VSL
R1 Not Applicable.
Moderate VSL
The Transmission
Owner failed to do one
of the following:
Document or maintain
or publish Facility
connection
requirements as
specified in the
Requirement
OR
Failed to include one
High VSL
Severe VSL
The Transmission
The Transmission
Owner failed to do one Owner did not
of the following:
develop Facility
connection
Failed to include (2) of requirements.
the components as
specified in R1.1, R1.2
or R1.3
OR
Failed to document or
maintain or publish its
Facility connection
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
R2 The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 45 calendar
days but less than or
equal to 60 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 60 calendar
days but less than or
equal to 70 calendar
days after having an
Agreement to evaluate
the reliability impact of
interconnecting a third
party Facility to the
Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
requirements as
specified in the
Requirement and
failed to include one
(1) of the components
as specified in R1.1,
R1.2 or R1.3.
The Generator Owner
failed to document and
publish Facility
connection
requirements until
more than 70 calendar
days but less than or
equal to 80 calendar
days after having an
Agreement to evaluate
the reliability impact
of interconnecting a
third party Facility to
the Generator Owner’s
existing Facility that is
used to interconnect to
the interconnected
Transmission systems.
R3 The responsible
entity’s Facility
connection
requirements failed to
address one of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address two of the parts
listed in Requirement
R3, parts 3.1.1 through
3.1.16.
The responsible
entity’s Facility
connection
requirements failed to
address three of the
parts listed in
Requirement R3, parts
3.1.1 through 3.1.16.
R4 The responsible entity
made the requirements
available more than
five business days but
less than or equal to 10
business days after a
request.
The responsible entity
made the requirements
available more than 10
business days but less
than or equal to 20
business days after a
request.
The responsible entity
made the requirements
available more than 20
business days less than
or equal to 30 business
days after a request.
The Generator
Owner failed to
document and
publish Facility
connection
requirements until
more than 80 days
after having an
Agreement to
evaluate the
reliability impact of
interconnecting a
third party Facility
to the Generator
Owner’s existing
Facility that is used
to interconnect to
the interconnected
Transmission
systems.
The responsible
entity’s Facility
connection
requirements failed
to address four or
more of the parts
listed in
Requirement R3,
parts 3.1.1 through
3.1.16.
The responsible
entity made the
requirements
available more than
30 business days
after a request.
F.E. Regional Differences
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
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S ta n d a rd FAC-001-01 — Fa c ility Co n n e c tio n Re q u ire m e nts
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
TBD
Added requirements for Generator Owner
and brought overall standard format up to
date.
Revision under Project
2010-07
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: December 1, 2011
Effective Date: April 1, 2005
6 of 6
Implementation Plan for FAC-001-1—Facility
Connection Requirements
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. FAC-001-0 –
Facility Connection Requirements will be retired at midnight the day before FAC-001-1 becomes
effective.
Compliance with Standard
Since this version of the standard imposes no changes to Transmission Owners from those in the FERCapproved version of the standard, the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners upon approval, as
detailed below.
The proposed changes to the FERC-approved version of this standard only address Generator Owner
applicability and requirements (add Generator Owner to section 4.2, introduce a new requirement
(R2), and modify one existing requirement (now R3)). Therefore, this implementation plan only
identifies a compliance timeframe for Generator Owners to which this standard will apply.
Effective Date
There are two effective dates associated with this standard:
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where
no regulatory approval is required, all requirements applied to the Transmission Owner and
Regional Entity become effective upon Board of Trustees’ adoption.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities.
In those jurisdictions where no regulatory approval is required, all requirements applied to the
Generator Owner become effective on the first calendar day of the first calendar quarter one
year after Board of Trustees’ adoption.
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1a
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity.
J a n u a ry 31, 2012
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Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
2.1a
XX
Errata change: Edited R2 to add “…and
generator interconnection Facility…”
Revision under Project
2010-07
J a n u a ry 31, 2012
2 of 2
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
A. Introduction
1.
Title:
Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
2.
Number:
3.
Purpose:
Ensure all transmission and generation Protection System Misoperations
affecting the reliability of the Bulk Electric System (BES) are analyzed and mitigated.
4.
Applicability
PRC-004-2.1a
4.1. Transmission Owner.
4.2. Distribution Provider that owns a transmission Protection System.
4.3. Generator Owner.
5.
(Proposed) Effective Date: The first day of the first calendar quarter, one year after
applicable In those jurisdictions where regulatory approval; or in is required, all requirements
become effective upon approval. In those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter one year afterall requirements become
effective upon Board of Trustees’ adoption.
B. Requirements
R1.
The Transmission Owner and any Distribution Provider that owns a transmission Protection
System shall each analyze its transmission Protection System Misoperations and shall develop
and implement a Corrective Action Plan to avoid future Misoperations of a similar nature
according to the Regional Entity’s procedures.
R2.
The Generator Owner shall analyze its generator and generator interconnection Facility
Protection System Misoperations, and shall develop and implement a Corrective Action Plan to
avoid future Misoperations of a similar nature according to the Regional Entity’s procedures.
R3.
The Transmission Owner, any Distribution Provider that owns a transmission Protection
System, and the Generator Owner shall each provide to its Regional Entity, documentation of
its Misoperations analyses and Corrective Action Plans according to the Regional Entity’s
procedures.
C. Measures
M1. The Transmission Owner, and any Distribution Provider that owns a transmission Protection
System shall each have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M2. The Generator Owner shall have evidence it analyzed its Protection System Misoperations and
developed and implemented Corrective Action Plans to avoid future Misoperations of a similar
nature according to the Regional Entity’s procedures.
M3. Each Transmission Owner, and any Distribution Provider that owns a transmission Protection
System, and each Generator Owner shall have evidence it provided documentation of its
Protection System Misoperations, analyses and Corrective Action Plans according to the
Regional Entity’s procedures.
D. Compliance
1.
Compliance Monitoring Process
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010De c e m b e r 1, 2011J a n u a ry 31, 2012
1 of 3
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
1.1. Compliance Enforcement Authority
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
The Transmission Owner, and Distribution Provider that own a transmission Protection
System and the Generator Owner that owns a generation or generator interconnection
Facility Protection System shall each retain data on its Protection System Misoperations
and each accompanying Corrective Action Plan until the Corrective Action Plan has been
executed or for 12 months, whichever is later.
The Compliance Monitor shall retain any audit data for three years.
1.5. Additional Compliance Information
The Transmission Owner, and any Distribution Provider that owns a transmission
Protection System and the Generator Owner shall demonstrate compliance through selfcertification or audit (periodic, as part of targeted monitoring or initiated by complaint or
event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1, 2005
1. Changed incorrect use of certain hyphens (-)
to “en dash” (–) and “em dash (—).”
2. Added “periods” to items where
appropriate.
Changed “Timeframe” to “Time Frame” in
item D, 1.2.
01/20/06
2
TBD
Modified to address Order No. 693
Directives contained in paragraph 1469.
Revised.
2.1a
XX
Errata change: Edited R2 to add “…and
Revision under Project
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010De c e m b e r 1, 2011J a n u a ry 31, 2012
2 of 3
Standard PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation
Protection System Misoperations
generator interconnection Facility…”
Ad o p te d b y Bo a rd o f Tru s te e s : Au g u s t 5, 2010De c e m b e r 1, 2011J a n u a ry 31, 2012
2010-07
3 of 3
Implementation Plan for PRC-004-2.1a—
Analyis of Transmission and Generation
Protection System Misoperations
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-004-2a will
be retired when PRC-004-2.1a becomes effective.
Compliance with Standard
The proposed change to Requirement R2 is a clarifying change. While there was no reliability gap in the
previous version of the standard, if applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection System
Misoperations, exclusive of its generator interconnection Facility. The errata change to R2 makes clear
that generator interconnection Facilities are also part of Generator Owners’ responsibility in the
context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption.
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. Many of these standards and requirements had been addressed in
the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad
Hoc Report) and additional standards were reviewed as a result of informal discussions with NERC and
FERC staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004 and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new,
glossary terms.
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Project 2010-07 Technical Justification Document
2
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT agrees
with that intended exclusion in principle; as it discusses in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT recognizes that in
many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2)
the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for
exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, sections 4.3.1 of both
versions of FAC-003 (which address applicable generation Facilities) now state: “Overhead transmission
Project 2010-07 Technical Justification Document
3
lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating
switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…” The SDT took into consideration all comments submitted in both formal
comment periods, and believes that this exemption now adequately addresses the reliability impact for
a majority of the Facilities, while balancing the efforts necessary to support the standard from all
entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
Project 2010-07 Technical Justification Document
4
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
Ad Hoc Report*
X
X
X
X
X
X
X
NERC Directive
FERC Order
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
Project 2010-07 Technical Justification Document
5
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
Project 2010-07 Technical Justification Document
6
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
Project 2010-07 Technical Justification Document
7
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Project 2010-07 Technical Justification Document
8
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
Project 2010-07 Technical Justification Document
9
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
Project 2010-07 Technical Justification Document
10
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Project 2010-07 Technical Justification Document
11
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
Project 2010-07 Technical Justification Document
12
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
Project 2010-07 Technical Justification Document
13
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
Project 2010-07 Technical Justification Document
14
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
15
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
As part of its work on Project 2010-07—Generator Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability standards and 102 requirements to determine
what changes are necessary to close a reliability gap with respect to what is commonly known as the
generator interconnection Facility. The majorityMany of these standards and requirements had been
addressed in the Final Report from the Ad Hoc Group for Generator Requirements at the Transmission
Interface (Ad Hoc Report),) and additional standards have beenwere reviewed, and will continued to
be reviewed, as a result of informal discussions with NERC and FERC staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby radialsole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
radialsole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate radialsole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, would require
substantially more data and modeling responsibilities, and would detract from the entities’ primary
functions: to own and operate their generation equipment – including any Facilities owned and
operated at voltages of 100 kV or greater that connect to the interconnected system – in a reliable
manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document). with the statement that the alert applied to
generator interconnection tie lines that are radial only and do not serve load “if the generator is
considered part of the bulk electric system”). While this applies to a specific NERC Recommendation,
the SDT considers this compelling evidence that the paradigm for thinking about generator
interconnection Facilities is shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004. and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and to postpone discussions onnot, at this time, propose revisions to
existing, or creation of new, definitions until the standards have been successfully balloted. glossary
terms.
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
Project 2010-07 Technical Justification Document
2
additional standards that had been proposed for substantive modification in the Ad Hoc Report.and
requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that
a regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). After reviewing
formal comments, the The SDT agreed to revise theagrees with that intended exclusion so that it
applies to a Facility if its length is “one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard” to approximate line of sign from a fixed point. Other than revising this
exclusion,in principle; as it discusses in the document titled “Technical Justification Project 2010-07
Generator Requirements at the Transmission Interface,” the SDT applied the same criteria to the
Generator Owner as applies to the Transmission Owner in the current FERC approved version of this
standard as well as one approved by stakeholders (under Project 2007-07) in February 2011. The SDT is
Project 2010-07 Technical Justification Document
3
communicating with NERC staffrecognizes that in many cases, generation Facilities are (1) staffed and
the Project 2007-07 SDT to ensure that changes to this standard will be coordinated before submitting
to NERC’s Board of Trustees, but feels compelled to continue to posting both versions until the
outcome of Project 2007-07 efforts is cleareroverhead portion is within line of sight or (2) the overhead
Facility is over a paved surface. Stakeholders have generally supported the rationale for exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, sections 4.3.1 of both
versions of FAC-003 (which address applicable generation Facilities) now state: “Overhead transmission
lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating
switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…” The SDT took into consideration all comments submitted in both formal
comment periods, and believes that this exemption now adequately addresses the reliability impact for
a majority of the Facilities, while balancing the efforts necessary to support the standard from all
entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other SubstantiveStandards Considered by the Standard Modifications from the
Ad Hoc ReportDrafting Team
Project 2010-07 Technical Justification Document
4
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. Below, the SDT provides its reasons for not proposing the substantive changes
that were included in the Ad Hoc Report (that is, a change in applicability or new requirement, beyond
simply adding the text “including its Generator Interconnection Facility” to an existing requirement).
As Project 2010-07 continues, the SDT will work with FERC staff, NERC staff, and industry groups to
determine if its list of proposed standards is supported industry-wide, and whether other standards
need to be considered.During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
Ad Hoc Report*
X
X
X
X
X
X
X
Project 2010-07 Technical Justification Document
NERC Directive
FERC Order
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
5
TOP-008-1
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
infersimplies that Generator Operators need to provide their underfrequency settings to their
respective Transmission Operator. Further, Generator Operators typically do not have the technical
expertise or access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Project 2010-07 Technical Justification Document
6
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
Project 2010-07 Technical Justification Document
7
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
Project 2010-07 Technical Justification Document
8
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially arrived at this decisiondetermined that IRO-005-2 did not require
modification because of the plannedOctober 2011 retirement of IRO-005-2the standard. In subsequent
meetings, the SDT also reached the conclusion that there is no reliability gap as PRC-001-1 R2 already
requires the Generator Operator to notify reliability entities of relay or equipment failures. The SDT
believes that a Special Protection System is a form of protection system and therefore any degradation
or potential failure to operate as expected would be required to be reported by the Generator
Operator to reliability entities (Balancing Authorities, Transmission Operators, and Reliability
Coordinators).
Personnel Perform ance, Training, and Qualifications (PER) Standards
Project 2010-07 Technical Justification Document
9
The SDT also chose not to propose the revisionsPER Standards (PER-001-0 and PER-002-0 were
addressed in the Ad Hoc Report; PER-002-0 was addressed in the NERC Directive; and PER-003-1 was
addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority orand PER-002-0—Operating Personnel Training that were proposed by the Ad Hoc Group..
For PER-001-0, the Ad Hoc Group had proposed adding a new R2 that would read “Each Generator
Operator shall provide operating personnel with the responsibility and authority to implement realtime actions to ensure the stable and reliable operation of the Generation Facility and Generation
Interconnection Facility, and the responsibility and authority to follow the directives of reliability
authorities including the Transmission Operator and Balancing Authority.” To PER-002-0, the Ad Hoc
Group proposed adding the Generator Operator to R1 (“Each Transmission Operator, Generator
Operator, and Balancing Authority shall be staffed with adequately trained operating personnel”) and
adding a new R3 that would read: “Each Generator Operator shall implement an initial and continuing
training program for all operating personnel that are responsible for operating the Generator
Interconnection Facility that verifies the personnel’s ability and understanding to operate the
equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.".”
Project 2010-07 Technical Justification Document
10
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changechanges to PER-002-0 and Order 742. Generator
Operators who deal with interconnection facilitiesFacilities at individual generating plants, on the other
hand, typically do not receive reliability-based orders specific to the interconnection Facilities and are
therefore not covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1
R3 already requires Generator Operators are, under currently approved reliability standards, required
to follow the directives issued by a Balancing Authority, Reliability Coordinator orof the appropriate
Transmission Operator. Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work untilunless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
Transm ission Operations (TOP) Standards
For TOP standards, the Ad Hoc Group proposed a number of new requirements that the SDT does not
see as supportive of reliability. This set of standards was somewhat difficult to analyze, as the Project
2007-03—Real-time Transmission Operations drafting team has made significant changes to TOP-001
through TOP-008, resulting in three proposed TOP standards where are currently eight (see the
project’s Implementation Plan). The Project 2010-07 reviewed both the FERC-approved TOP standards
and the fifth draft of the modified standards in Project 2007-03 to determine whether it needed to
propose any additional changes to cover radial generator interconnection Facilities. In addition, the
Project 2010-07 SDT contacted the Project 2010-07 to get its opinion as to whether there might be any
reliability gaps related to generator interconnection facilities. No such changes will be proposed for the
reasons outlined below.
The Ad Hoc Group proposed adding two new requirements to The FERC Order does not address PER001-0 or PER-002-0, but it does address PER-003-1. In paragraphs 67 and 81 of the FERC Order, FERC
expresses concern that operational control over the transmission line breakers owned by the entities
in question are not under the control of NERC certified operators. FERC goes on to say that “Reliability
Standard PER-003-001 requires NERC certification of all operators that have responsibility for the realtime operation of the interconnected Bulk Electric System. When switching the tie-line in or out of
service, operators must have the appropriate credentials and training to properly perform the
switching and coordinate the switching to prevent adverse impacts such as the introduction of faults
on the system.”
Project 2010-07 Technical Justification Document
11
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Project 2010-07 Technical Justification Document
12
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that this change is necessary.TOP-001-1 needs to
apply to Generator Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP003-2, as outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator
to coordinate its current-day, next-day, and seasonal operations with its Host Balancing Authority and
Transmission Service Provider. These entities are, in turn, required to coordinate with their respective
Project 2010-07 Technical Justification Document
13
Transmission Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-0032, as outlined in Project 2007-03’s Implementation Plan) requires each Balancing Authority and
Transmission Operator to coordinate with neighboring Balancing Authorities and Transmission
Operators and with its Reliability Coordinator. With these requirements, Generator Operators are
already required to provide necessary operations information to Transmission Operators. To require
the same thing in TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Project 2010-07 Technical Justification Document
14
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group alsohad proposed a new requirement, R7, for TOP-004-2—Transmission Operations
that would read: “The Generator Operator shall operate its Generator Interconnection Facility within
its applicable ratings.” The SDT does not agree that a reliability gap exists, because an operator has a
fiduciary obligation to protect a Facility for which it is operationally responsible. FAC-008-1—Facility
Ratings Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that
the reason for establishing a ratings methodology and communicating facility ratingsFacility Ratings to
the Reliability Coordinator, Planning Authority, Transmission Planner, and Transmission Operator is
“…for use in reliable planning and operation of the Bulk Electric System.” Further, TOP-004-2 is
proposed to be retired under the work of the Project 2007-03 drafting team. Its requirements will
either be deleted or assigned elsewhere.
The Ad Hoc team proposed to addTOP-006-1—Monitoring System Conditions (addressed in the NERC
Directive; the SDT believes NERC intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Project 2010-07 Technical Justification Document
15
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
deletingdelete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
radialsole-use interconnection Facilities. The changes to FAC-001 and, FAC-003 (, and now PRC-004)
have been supported by stakeholders during comment periods, and there has been no strong support
of technical justification provided for bringing other standards into the scope of this project.
That said, the SDT recognizes the success of its work depends on stakeholders, NERC, and FERC
agreeing that generator requirements at the transmission interface are covered under NERC Reliability
Standards, both for the sake of reliability and to prevent further unwarranted registration of Generator
Owners and Generator Operators as Transmission Owners and Transmission Operators. If the SDT’s
work does not close the gap in the eyes of all parties, that work will have been unsuccessful, so the SDT
is considering all feedback it receives with request to this project. While it is posting changes to only
FAC-001, FAC-003, and PRC-004, and stands by that decision, it will continue to consider whether
glossary term additions/modifications and modifications to other standards could enhance the
reliability impact of this project. Based on conversations with NERC and FERC staff, and review of
FERC’s Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind
Corridor Phase I (135 FERC ¶ 61,241), the SDT is discussing whether it should consider the following
requirements for further review: EOP-005-1 R1, R2, R6, R7; FAC-014-2 R2; PER-003-1 R1, R1.1, R1.2;
PRC-001-1 R2, R2.2, R4, R6; PRC-004-1 R1; TOP-001 R1; TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4; and TOP006-1 R3. The SDT is actively seeking stakeholder feedback as to whether, in light of these orders, it
should consider additional standards and or new or modifications to existing definitions as it proceeds
with its work.
Project 2010-07 Technical Justification Document
16
Technical Justification: FAC-001-1
Project 2010-07 Generator Requirements at the Transmission Interface
In response to the June 17-July 17, 2011 formal posting of the proposed standard changes in Project
2010-07, the standard drafting team (SDT) received stakeholder comments on FAC-001-1 expressing
concern about the feasibility of a Generator Owner receiving and executing an interconnection request
on one of its interconnection Facilities, as well as concern about the market-related processes that
would go along with such an interconnection request. In this technical justification document, the SDT
seeks to further clarify its rationale for making the proposed FAC-001-1 applicable to qualifying
Generator Owners.
While the SDT understands that interconnection requests for Generator Owner Facilities are still
relatively rare, in the past (for instance, 134 FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13),
Generator Owners have received or have been directed to execute interconnection requests for their
Facilities. The SDT acknowledges that FERC does not have jurisdiction over all Generator Owners, but
realizes that the potential exists for a third party to request to interconnect its planned generator with
an existing generator interconnection Facility (whose use at the time of the request is solely to
transmit capacity, energy, and ancillary services from the existing generator).
The SDT discussed the various ways such an interconnection could occur and agrees that if the third
party interconnection could be accomplished without the need for the existing Generator Owner to
develop its own connection requirements and system performance requirements and determine
impacts on the interconnected transmission systems, this standard need not apply to the Generator
Owner. And the SDT agrees that in many cases, these connection requirements, system performance
requirements, and determined impacts on the interconnected transmission systems are currently
determined by entities registered as either a Transmission Owner, Transmission Planner, and/or
Transmission Service Provider. However, the SDT remains convinced (based on the orders cited above)
that there may be occasions where FERC or another regulatory agency compels the Generator Owner
to allow a third party to interconnect its planned generator with an existing generator interconnection
Facility. Where this occurs, the SDT feels it is necessary for the existing owner of that generator
interconnection Facility to provide connection requirements to the third party that requests
interconnection. The SDT also believes, and many comments seem to support, that performance
requirements and a determination of impact to the interconnected transmission systems need to be
evaluated by some entity. The question becomes which entity.
The SDT can only work within the standards development process. We cannot address other regulatory
issues such as FERC-mandated open transmission access (Order 888 and subsequent) or state or
provincial jurisdiction over generation or transmission assets. While we acknowledge these
mechanisms exists and may come into play in the scenarios described in the proposed FAC-001-1, we
as the SDT can only deal within the context of reliability standards. For this reason, R2 indicates that
FAC-001-1 applies only when a Generator Owner has an executed Agreement to evaluate the reliability
impact of interconnecting a third party Facility to the Generator Owner’s existing Facility.
The SDT’s reasoning here is that if the owner of the existing generator interconnection Facility agrees,
or is compelled, to allow a third party to interconnect, and can do so using existing agreements,
contracts, and/or tariffs (and thereby avoid having an executed Agreement to evaluate the reliability
impact of interconnecting third party Facility to the Generator Owner’s existing Facility), and thus avoid
having to develop its own connection requirements or perform impact studies, it will. In this example,
it is likely that the existing Transmission Owner, Transmission Planner, and/or Transmission Service
Provider processes and Agreements will be utilized and the purpose of FAC-001-1 will be met without
applying this standard to the Generator Owner.
If, on the other hand, the owner of the existing generator interconnection Facility agrees, or is
compelled, to allow a third party to interconnect, but cannot do so without having to develop its own
connection requirements or perform impact studies, the SDT believes that the potential for a reliability
gap exists. This might occur, for instance, if the owner of an existing generator interconnection Facility
was compelled to allow interconnection and to implement open transmission access. In this example,
(under FERC Order 888 and subsequent orders), the existing interconnection owner becomes a
Transmission Service Provider and is required to have an Open Access Transmission Tariff (OATT).
FERC’s pro forma OATT requires the Transmission Service Provider to, among other things, perform
system impact and feasibility studies. In order to do so, such studies must be coordinated with other
Transmission Service Providers and Transmission Planners. And, to further complicate the issue, the
SDT has been informed that in Texas, a Generator Owner is not allowed to own transmission.
Clearly, these issues are complex and not all are within the jurisdiction of federal or provincial
regulators. For these reasons, the SDT took the only approach it found workable. If, and only if, the
existing owner of a generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply. The SDT believes that this is most likely to occur if the owner of an existing
generator interconnection Facility is compelled to allow a third party to interconnect and adopt open
transmission access. However, the SDT cannot be certain this is the only example and it therefore
proposes to add this new requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third party to interconnect,
have the necessary expertise to conduct the required interconnect studies to meet this standard.
However, the SDT believes that, upon executing such Agreement, the Generator Owner will have to
acquire such expertise. How the Generator Owner chooses to do so is not for the SDT to determine.
The SDT is tasked with identifying potential reliability gaps and addressing such gaps through the
standards development process.
Project 2010-07 Technical Justification for FAC-001-1
2
The SDT does agree with many comments asking that the Generator Owner not be required to
maintain its connection requirements, and there was robust discussion among the team and observers.
Some were concerned that, without an obligation to maintain, there would not be a review to ensure
compliance with NERC Reliability Standards and applicable Regional Entity, subregional, Power Pool,
and individual Transmission Owner planning criteria. Others were concerned that the third party
requesting interconnection might not actually interconnect, but the owner of the existing generator
interconnection Facility would, having executed an evaluation agreement, be forever obligated to
maintain connection requirements. In the end, the SDT agreed that if the owner of the existing
generator interconnection Facility adopted open access or was determined to be providing
“transmission service” it was likely that its existing registration would be re-evaluated and that the
issue would be more appropriately addressed at that time. The SDT has therefore agreed to remove
maintenance requirements for Generator Owners from both Requirement R2 and Requirement R4 in
the proposed FAC-001-1.
We hope that you have found this explanation of our rationale helpful, but if you have further
suggestions for improvement or clarity, please submit them in your comments on this latest posting.
Project 2010-07 Technical Justification for FAC-001-1
3
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FAC001-1
R1
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO). Because the drafting
team made no changes to R1, the
team determined that any further
changes to R1’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors.. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
The drafting team made no
changes to the R1 VSLs filed by
NERC staff on March 21, 2011 (in
Supplemental Information to the
NERC Compliance Filing in
Response to the Order on
Violation Severity Levels Proposed
by the ERO), except to correct
typographical errors. Because the
drafting team made no changes to
R1, the team determined that any
further changes to R1’s VSLs would
be outside of the scope of Project
2010-07.
FAC001-1
R2
The VSLs for R2 are written in
accordance with NERC’s VSL
Guideline’s formatting
recommendations. The
requirement is not of the pass/fail
variety, so the VSL assignments
have been gradated based on
when the Generator Owner
documented and published the
Facility connection requirements.
As is recommended by NERC’s VSL
Guidelines, the drafting team
Because this is a new requirement,
there is no current level of
compliance with which the VSL
assignments can be compared.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. The
VSL assignments are consistent
with the requirement and the
degree of compliance can be
determined objectively and with
certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
The proposed text is clear, specific,
and does not contain general,
relative or subjective language
(and is not subject to the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team compared the
VSLs to the requirement language
to ensure that the VSLs do not
redefine or undermine the
requirement’s reliability goal. After
modifying “Transmission Owner”
to “responsibility entity”, the VSL
assignments are consistent with
the requirement and the degree of
compliance can be determined
objectively and with certainty.
The VSLs are based on a single
violation, not on a cumulative
number of violations of the same
requirement over a period of time,
thus fulfilling Guideline 4.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
identified a reasonable delay for
the Lower VSL and then used 10day increments to develop the
Moderate, High, and Severe VSLs.
FAC001-1
R3
For its proposed changes to VSLs
for FAC-001-1 R3, the drafting
team used the FERC-approved
VSLs (then FAC-001-0 R2) in 135
FERC ¶ 61,166 as a starting point.
The VSLs were already
appropriately gradated with
penalties based on the
recommendation for requirements
with parts that contribute equally
to the requirement, and removing
the second half of R3’s Severe VSL
simply avoids any double jeopardy
compliance issues, as indicated in
the Guideline 2 explanation.
possibility of multiple
interpretations), satisfying
Guideline 2b.
The drafting team’s slight
modification to the Severe VSL for
R3 does not signal a lower
compliance threshold than
previously existed.
The requirement has gradated
VSLs; therefore, Guideline 2a is not
applicable. The gradated VSLs
ensure uniformity and consistency
among all approved Reliability
Standards in the determination of
penalties.
The drafting team determined that
the second half of the Severe VSL
in R3 (“The responsible entity does
not have Facility connection
requirements”) could lead to
double jeopardy because of its
redundancy with the Severe VSLs
in R1 (“The Transmission Owner
did not develop Facility connection
requirements”) and R2 (“The
Generator Owner failed to
document and publish and
thereafter maintain Facility
connection requirements until
more than 80 days…”). Thus, the
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
Compliance with NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Guideline 3
Guideline 4
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
second half of the VSL for R3 has
been deleted.
With this change, the text is clear,
specific, and does not contain
general, relative or subjective
language (and is not subject to the
possibility of multiple
interpretations), satisfying
Guideline 2b.
FAC001-1
R4
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because, with this
posting, the drafting team made
no changes to R4 compared to the
FERC approved version (then R3),
the team determined that any
further changes to R4’s VSLs would
be outside of the scope of Project
2010-07.
VRFs for FAC-001-1:
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
The drafting team made no
changes to the R4 VSLs (then VSLs
for R3) approved by FERC in 135
FERC ¶ 61,166. Because the
drafting team made no changes to
R4 compared to the FERC
approved version (then R3), the
team determined that any further
changes to R4’s VSLs would be
outside of the scope of Project
2010-07.
Project 2010-07—Generator Requirements at the Transmission Interface
Justification for Nonbinding Poll
The VRFs for FAC-001-1 were transferred from NERC’s VRF Matrix – which includes VRFs that have already been approved by FERC – to bring the
formatting of the standard up to date. A Medium VRF was added to new Requirement R2, which applies to Generator Owners, to match the
Medium VRF for the comparable Requirement R1, which applies to Transmission Owners.
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Entity on request
(within 30 calendar days). The documentation of the program implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
D. Compliance
Ap ril 23, 2012
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
Ap ril 23, 2012
2 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
Ap ril 23, 2012
3 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
Ap ril 23, 2012
4 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 2
Requirement Number and Text of Requirement
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
Question:
1. Does R1 require a maintenance and testing program for the battery chargers for the “station batteries”
that are considered part of the Protection System?
2. Does R1 require a maintenance and testing program for auxiliary relays and sensing devices? If so,
what types of auxiliary relays and sensing devices? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of transmission line re-closing relays?
4. Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry with
relays and devices that control actions on breakers, etc., or does R1 require a program for the entire
circuit from the battery charger to the relays to circuit breakers and all associated wiring?
5. For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing program?
Response:
1. While battery chargers are vital for ensuring “station batteries” are available to support Protection
System functions, they are not identified within the definition of “Protection Systems.” Therefore,
PRC-005-1 does not require maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not include auxiliary relays; therefore,
maintenance and testing of such devices is not explicitly required. Maintenance and testing of such
devices is addressed to the degree that an entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded auxiliary relays. Maintenance and testing of
devices that respond to quantities other than electrical quantities (for example, sudden pressure
relays) are not included within Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a basis
for the way they address this item, and 3) execute the program. PRC-005-1 does not establish specific
additional requirements relative to the scope and/or methods included within the program.
5. “Associated communication systems” refer to communication systems used to convey essential
Protection System tripping logic, sometimes referred to as pilot relaying or teleprotection. Examples
include the following:
•
communications equipment involved in power-line-carrier relaying
•
communications equipment involved in various types of permissive protection system
Ap ril 23, 2012
5 of 6
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
applications
•
direct transfer-trip systems
•
digital communication systems (which would include the protection system communications
functions of standard IEC 618501 as well as various proprietary systems)
Ap ril 23, 2012
6 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1a1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
To be determined
5.
Effective Date:
In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Reliability
OrganizationEntity on request (within 30 calendar days). The documentation of the program
implementation shall include:
R2.1.
Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Ap ril 23, 2012
1 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability OrganizationEntity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels of Non-Compliance(no changes)
2.1. Level 1: Documentation of the maintenance and testing program provided was
incomplete as required in R1, but records indicate maintenance and testing did occur
within the identified intervals for the portions of the program that were documented.
2.2. Level 2: Documentation of the maintenance and testing program provided was complete
as required in R1, but records indicate that maintenance and testing did not occur within
the defined intervals.
2.3. Level 3: Documentation of the maintenance and testing program provided was
incomplete, and records indicate implementation of the documented portions of the
maintenance and testing program did not occur within the identified intervals.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation,
was not provided.
E. Regional Differences
None identified.
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Ap ril 23, 2012
2 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1
February 7,
2006
Adopted by NERC Board of Trustees
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Project 2009-17
interpretation
Ap ril 23, 2012
3 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Ap ril 23, 2012
4 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 2
Requirement Number and Text of Requirement
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
Question:
1. Does R1 require a maintenance and testing program for the battery chargers for the “station batteries”
that are considered part of the Protection System?
2. Does R1 require a maintenance and testing program for auxiliary relays and sensing devices? If so,
what types of auxiliary relays and sensing devices? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of transmission line re-closing relays?
4. Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry with
relays and devices that control actions on breakers, etc., or does R1 require a program for the entire
circuit from the battery charger to the relays to circuit breakers and all associated wiring?
5. For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing program?
Response:
1. While battery chargers are vital for ensuring “station batteries” are available to support Protection
System functions, they are not identified within the definition of “Protection Systems.” Therefore,
PRC-005-1 does not require maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not include auxiliary relays; therefore,
maintenance and testing of such devices is not explicitly required. Maintenance and testing of such
devices is addressed to the degree that an entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded auxiliary relays. Maintenance and testing of
devices that respond to quantities other than electrical quantities (for example, sudden pressure
relays) are not included within Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a basis
for the way they address this item, and 3) execute the program. PRC-005-1 does not establish specific
additional requirements relative to the scope and/or methods included within the program.
5. “Associated communication systems” refer to communication systems used to convey essential
Protection System tripping logic, sometimes referred to as pilot relaying or teleprotection. Examples
include the following:
•
communications equipment involved in power-line-carrier relaying
•
communications equipment involved in various types of permissive protection system
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Ap ril 23, 2012
5 of 6
Standard PRC-005-1a1.1b — Transmission and Generation Protection System Maintenance and
Testing
applications
•
direct transfer-trip systems
•
digital communication systems (which would include the protection system communications
functions of standard IEC 618501 as well as various proprietary systems)
Adopted by NERC Board of Trustees: February 7, 2006
Interpretation adopted by NERC Board of Trustees (Appendix 1): February 17, 2011
Ap ril 23, 2012
6 of 6
Implementation Plan for PRC-005-1.1a—
Transmission and Generation Protection
System Maintenance and Testing
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-005-1a will
be retired when PRC-005-1.1a becomes effective.
Compliance with Standard
The proposed changes to Requirement R1 and R2 are clarifying changes. While there was no reliability
gap in the previous version of the standard, if applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection
System, exclusive of its generator interconnection Facility Protection System. The errata changes to R1
and R2 make clear that generator interconnection Facilities are also part of Generator Owners’
responsibility in the context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption.
Unofficial Comment Form
Generator Requirements at the Transmission Interface (Project 2010-07)
Please DO NOT use this form to submit comments. Please use the electronic comment form to
submit comments on the first formal posting for Project 2010-07—Generator Requirements at the
Transmission Interface. The electronic comment form must be completed by April 16, 2012.
2010-07 Project Page
If you have questions please contact Mallory Huggins at mallory.huggins@nerc.net or 202-3832629.
Background
During the formal comment period that ended on November 18, 2011, the SDT asked the following
question: “The SDT is attempting to modify a set of standards so that radial generator
interconnection Facilities are appropriately accounted for in NERC’s Reliability Standards, both to
close reliability gaps and to prevent the unnecessary registration of GOs and GOPs as TOs and
TOPs. Does the set of standards currently posted achieve this goal?” In response, stakeholders
suggested that the proposed revisions to PRC-004-2 should also be made to PRC-005. Accordingly,
the SDT has revised PRC-005-1.1a, and is posting it for a formal 45-day comment period and initial
ballot. The Standards Committee has authorized waiving the initial 30-day comment period
because the changes to PRC-005-1.1a are minor.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator
Operators operate Elements and Facilities that are considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to Transmission Owners and Transmission
Operators who own and operate Transmission Elements and Facilities that are part of the
integrated grid.
As part of the BES, generators affect the overall reliability of the BES. However, registering a
Generator Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has
been the solution in some cases in the past, may decrease reliability by diverting the Generator
Owner’s or Generator Operator’s resources from the operation of the equipment that actually
produces electricity – the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES
by clearly describing which standards need to be applied to generator interconnection Facilities that
are not already applicable to Generator Owners or Generator Operators. The SDT believes that
properly applying PRC-005-1.1a to Generator Owners as proposed in the redline standard posted
for comment supports this objective.
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
1
You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection
Facility” in Requirements R1 and R2 of PRC-005-1.1a. While there was no reliability gap in the
previous version of the standard, if the Requirements were applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection
Systems, exclusive of its generator interconnection Facility Protection Systems. The clarifying changes to R1
and R2 make clear that generator interconnection Facilities are also part of Generator Owners’ responsibility
in the context of this standard. Do you support the addition of the phrase “or generator
interconnection Facility” to accomplish this clarification?
Yes
No
Comments:
2. Do you have any other comments that you have not yet addressed? If yes, please explain.
Yes
No
Comments:
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
2
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission
Interface
Ballot Window Open April 6, 2012 through April 16, 2012
Available April 6
An initial ballot for PRC-005-1.1a – Transmission and Generation Protection System Maintenance and
Testing is open Friday, April 6 through 8 p.m. Eastern on Monday, April 16, 2012.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standards by clicking here.
Special Instructions for Submitting Comments with a Ballot
Please note that comments submitted during the formal comment period, the ballot and the nonbinding polls use the same electronic form. Therefore, it is NOT necessary for ballot pool members to
submit more than one set of comments. Companies or entities with representatives in multiple
segments of the ballot pool may submit a single set of comments by identifying themselves as a
“group” on the comment form. Likewise, it is preferable for a group of separate entities that develop
comments jointly to submit the comments as a “group.” The drafting team requests that all
stakeholders (ballot pool members as well as other stakeholders) submit all comments through the
electronic comment form, and that companies in multiple segments as well as individual entities that
develop joint comments with other entities submit their comments as a “group,” with the list of
group members and their associated Industry Segments.
Next Steps
The drafting team will consider all comments received during the formal comment period and initial
ballot and if needed, make revisions to the standard.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators also affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying PRC-005-1.1a to Generator Owners as proposed in the redline standard posted for comment
supports this objective.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement – Project 2010-07
2
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission
Interface
Project 2010-07 Generator Requirements at the Transmission Interface
Ballot Pool Forming March 2 – 31, 2012
Formal Comment Period Open March 2 – April 16, 2012
Initial Ballot Window Open April 6 – 16, 2012
Available Friday, March 2, 2012
The Generator Requirements at the Transmission Interface drafting team has posted very limited
revisions to PRC-005-1a – Transmission and Generation Protection System Maintenance and Testing,
along with an implementation plan, for a parallel formal 45-day comment period and initial ballot.
Because of the limited nature of the changes, the Standards Committee has authorized waiving the
initial 30-day comment period.
Note that more substantive revisions to PRC-005-2 (under Project 2007-17 Protection System
Maintenance and Testing) are also posted for a parallel 30-day formal comment period and successive
ballot through March 28, 2012. The Project 2010-07 SDT recognizes this and supports the work of that
team, whose changes eliminate the need for the surgical addition of “generator interconnection
Facility” made in PRC-005-1.1a. Because the Project 2010-07 SDT cannot predict the outcome of
Project 2007-17 and wants to ensure that generator interconnection Facilities are appropriately
addressed in PRC-005 whether or not PRC-005-2 proceeds to NERC's Board this year, it has elected to
continue with its revisions to PRC-005-1.1a.
Instructions for Joining the Ballot Pool for Project 2010-07
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballot
of PRC-005-1.1a at the following page: Join Ballot Pool
During the pre-ballot windows, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list server for this ballot pool is: bp-2010-07_PRC-0051.1a_in@nerc.com
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial
copy of the comment form is posted on the project page.
Special Instructions for Submitting Comments with a Ballot
Please note that comments submitted during the formal comment period and ballot for the standard
all use the same electronic form, and it is NOT necessary for ballot pool members to submit more than
one set of comments. The drafting team requests that all stakeholders (ballot pool members as well as
other stakeholders) submit all comments through the electronic comment form.
Next Steps
An initial ballot of PRC-005-1.1a will begin on Friday, April 6, 2012 and end at 8 p.m. Eastern on
Monday, April 16, 2012.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators so affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying PRC-005-1.1a to Generator Owners as proposed in the redline standard posted for comment
supports this objective.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Announcement
Project 2010-07 PRC-005-1.1a
2
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd. NE.
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-07 PRC-005-1.1a
3
Standards Announcement
Project 2010-07 – Generator Requirements at the Transmission Interface
Initial Ballot Results
Now Available
An initial ballot of PRC-005-1.1a – Transmission and Generation Protection System Maintenance and
Testing standard concluded Monday, April 16, 2012:
Voting statistics for the ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Standard
PRC-005-1.1a – Transmission and Generation Protection
System Maintenance and Testing
Quorum
Approval
88.95 %
92.41%
Next Steps
The drafting team will consider all comments received during the formal comment period and initial
ballot. If the drafting team decides to make substantive revisions, the drafting team will submit the
revised standard and consideration of comments received for a quality review prior to posting for a
parallel formal 30-day comment period and successive ballot. If the drafting team determines that no
substantive changes are required to be responsive to the comments received, the standard will be
posted for a recirculation ballot.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities commonly known as generator interconnection Facilities considered by some entities
to be Transmission, these are most often radial Facilities that are not part of the integrated grid. As
such, they should not be subject to the same standards applicable to Transmission Owners and
Transmission Operators who own and operate Transmission Elements and Facilities that are part of the
integrated grid.
As part of the BES, generators also affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying PRC-005-1.1a to Generator Owners as proposed supports this objective.
The drafting team encourages all stakeholders to read the technical justification resource document it
has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate. For more information or assistance, please contact Monica
Benson at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
Ballot Results – Project 2010-07 | PRC-005-1.1a
2
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010 -07 PRC-005-1.1a
Password
Ballot Period: 4/6/2012 - 4/16/2012
Log in
Ballot Type: Initial
Total # Votes: 346
Register
Total Ballot Pool: 389
Quorum: 88.95 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
92.41 %
Vote:
Ballot Results: The drafting team is considering comments.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
102
8
84
28
96
51
0
9
3
8
389
#
Votes
1
0.4
1
1
1
1
0
0.5
0.2
0.7
6.8
#
Votes
Fraction
71
4
63
22
68
34
0
5
2
7
276
Negative
Fraction
0.922
0.4
0.9
0.917
0.895
0.85
0
0.5
0.2
0.7
6.284
Abstain
No
# Votes Vote
6
0
7
2
8
6
0
0
0
0
29
0.078
0
0.1
0.083
0.105
0.15
0
0
0
0
0.516
10
2
8
3
8
6
0
4
0
0
41
15
2
6
1
12
5
0
0
1
1
43
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Scott J Kinney
Kevin Smith
https://standards.nerc.net/BallotResults.aspx?BallotGUID=abf63bb5-8c91-4a8f-95f2-9b710ae9548d[4/18/2012 10:22:51 AM]
Ballot
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
FortisBC
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Michael B Bax
Joseph Turano Jr.
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Curtis Klashinsky
Jason Snodgrass
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
Joe D Petaski
Danny Dees
Ernest Hahn
Terry Harbour
Theresa Allard
Tim Reed
Cole C Brodine
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Kevin M Largura
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Ryan Millard
Ronald Schloendorn
John C. Collins
https://standards.nerc.net/BallotResults.aspx?BallotGUID=abf63bb5-8c91-4a8f-95f2-9b710ae9548d[4/18/2012 10:22:51 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
1
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dale Dunckel
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=abf63bb5-8c91-4a8f-95f2-9b710ae9548d[4/18/2012 10:22:51 AM]
Affirmative
Affirmative
Negative
Affirmative
View
View
View
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Ocala Electric Utility
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Benton County
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
Kenneth Simmons
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Skyler Wiegmann
William SeDoris
David Anderson
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Gloria Bender
Erin Apperson
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Reza Ebrahimian
Kevin McCarthy
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Tim Beyrle
Affirmative
Nicholas Zettel
John Allen
David Frank Ronk
Abstain
Affirmative
Affirmative
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Cowlitz County PUD
Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Eastern Municipal Power
Agency
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Castleton Energy Center
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Energy Services, Inc.
Essential Power, LLC
Exelon Nuclear
First Solar, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
GenOn Energy, Inc
Great River Energy
ICF International
Imperial Irrigation District
Invenergy LLC
JEA
Kansas City Power & Light Co.
Rick Syring
Russ Schneider
Frank Gaffney
Guy Andrews
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Cecil Rhodes
Affirmative
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Affirmative
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Shari Heino
Chifong Thomas
John Walsh
Daniel Mason
Jeanie Doty
Paul Cummings
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Tommy Drea
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Negative
Affirmative
Abstain
Affirmative
View
Negative
Negative
Abstain
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Dana Showalter
Affirmative
Brenda J Frazer
John R Cashin
Tracey Stubbs
Patrick Brown
Michael Korchynsky
Robert Jenkins
Kenneth Dresner
David Schumann
James W Mason
Preston L Walsh
Brent B Hebert
Marcela Y Caballero
Alan Beckham
John J Babik
Brett Holland
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
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Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
Proven Compliance Solutions
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
S N Fernando
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mitchell E Needham
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Claire Lloyd
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Nickesha P Carrol
Donald Schopp
Louis S. Slade
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Abstain
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Affirmative
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Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
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Affirmative
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Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
JDRJC Associates
JDRJC Associates
Massachusetts Attorney General
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
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Affirmative
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Affirmative
Affirmative
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Affirmative
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Affirmative
Peter H Kinney
David F. Lemmons
Brendan Kirby
Roger C Zaklukiewicz
James A Maenner
Jim Cyrulewski
Jim Cyrulewski
Jim Cyrulewski
Frederick R Plett
Brian Evans-Mongeon
Terry Volkmann
Negative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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https://standards.nerc.net/BallotResults.aspx?BallotGUID=abf63bb5-8c91-4a8f-95f2-9b710ae9548d[4/18/2012 10:22:51 AM]
Individual or group. (19 Responses)
Name (12 Responses)
Organization (12 Responses)
Group Name (7 Responses)
Lead Contact (7 Responses)
Contact Organization (7 Responses)
Question 1 (18 Responses)
Question 1 Comments (19 Responses)
Question 2 (18 Responses)
Question 2 Comments (19 Responses)
Group
Imperial Irrigation District (IID)
Jesus Sammy Alcaraz
IID
Yes
No
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
No
Individual
Keira Kazmerski
Xcel Energy
No
Xcel Energy does not believe that trying to implement a revision of PRC-005-1 at this point improves
the reliability of the grid. There are better means of clarifying the perceived “misperceptions” than
drafting a standard revision. This is particularly the case when PRC-005-2 is further along in the
process and is also posted for industry comment and ballot. The effort of the GOTO SDT is
counterproductive.
No
Individual
Dan Roethemeyer
Dynegy Inc.
Yes
No
Group
Imperial Irrigation District (IID)
Jesus Sammy Alcaraz
IID
Yes
No
Individual
John Bee
Exelon
Yes
The standard language should be clarified to allow for alternative testing programs, agreed upon by
both TO and GO, in cases where testing programs do not follow ownership of the equipment for all
Component Types so long as all of the protection for the generator interconnection facility is covered.
Individual
Art Salander
HindlePower, Inc
Yes
No
I beleive that the requirments as shown in 1-4a - c need to be better clarified as to the actual tasks
required. There seems to be no real distinction between Verification and inspection. There is no clear
reporting structure and the requirment to substitute Ohmic readings vs. discharge test is not basede
on any industry reliable standards. since there is much debate in the industry as to the validity if
Ohmic testing and it has not been accepted by the IEEE as an acceptbale practice I would rather see
terms in line with either IEEE standard or manufacvturer's recommendations.
Individual
John Seelke
Public Service Enterprise Group
Yes
No
Individual
Martin Kaufman
ExxonMobil Research and Engineering
No
The bulk electric system is contiguous. Therefore, any facility owned by the Generator Owner that is
used to connect the Generator Owner’s generation facilities to the bulk electric system is already
considered a bulk electric system asset and part of the Generator Owner’s generation facilities. As
stated by in the question above, the addition of the term “or generator interconnection Facility” does
not resolve a reliability gap or add any substance to the requirement
Yes
The SDT has utilized two terms in this round of the drafting process whose definitions are subject to
interpretation. The terms ‘generating station switchyard’ and ‘generator interconnection Facility’ need
to be defined to prevent inconsistent enforcement or need for the development of a Compliance
Application Notice. As referenced in our comments to FAC-003-X/3, when you try to apply the term
‘generating station switchyard’ to an industrial complex that contains multiple substations between
the GSU and utility interconnection facility (another substation) in order to measure the generator
lead line for the 1 mile quota, there are several candidates that appear to fit the criteria.
Group
Southwest Power Pool Standards Development Team
Jonathan Hayes
Southwest Power Pool
No
We would advise the Drafting team to take a look at the FERC OATT to reconcile the term “generator
interconnection facility “with Tariff term for the LGIA. This should clarify the point of delineation and
there should be no misconception of the language as written.
Yes
This effort seems to be redundant due to the work going on with PRC-005-2. We do not understand
why this change is being made and it wasn’t made very clear in the red line changes or in this
comment form background.
Individual
Michelle R D'Antuono
Ingleside Cogeneration LP
Yes
Since PRC-005-1 already requires the Generation Owner to maintain and test all their BES Protection
System components, it seems to Ingleside Cogeneration LP that the need to specify those which may
trip the interconnection facility as redundant. However, we do not believe that the Standard
Development Team’s modifications materially change the intent of the Standard – nor can they lead
an audit team to assign a double violation for a single incidence of non-compliance.
No
Individual
Dale Fredrickson
We Energies
Yes
No
Individual
Michael Falvo
Independent Electricity System Operator
Yes
The proposed implementation plan conflicts with Ontario regulatory practice respecting the effective
date of the standard. It is suggested that this conflict be removed by appending to the
implementation plan wording, after “applicable regulatory approval” in the Effective Dates Section A5
of the draft standard and P. 1 of the Implementation Plan, to the following effect: “, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.”
Group
Bonneville Power Administration
Chris Higgins
Transmission Reliability Program
Yes
Yes
Regarding Section 1.3 Data Retention, BPA believes that it would be difficult for an entity to provide
“other evidence” to demonstrate compliance when the data retention period is shorter than the time
since the last audit. BPA requests the drafting team to offer guidance as to what "other evidence"
could be provided other than what is already described in the measures. BPA believes that suggesting
there is some “other evidence” without providing a description leaves the TO’s and GO’s without clear
direction on how to comply with the standard. BPA suggests the data retention period should be three
years or since the time the last audit occurred, whichever is longer for each TO and GO to retain
evidence. Should the drafting team revise the Data Retention language to reflect BPA’s concerns, BPA
would vote in favor of PRC-005-1.1a.
Individual
Joe Petaski
Manitoba Hydro
Yes
No
Manitoba Hydro does not support the changes being proposed in Project 2010-07 in general. If a
Generator Owner is required to register as a TO, all the Requirements applicable to a TO should
apply. There is no need to change specific Reliability Standards to allow the Generator Owner to
perform only selected TO functions. For additional information, please see Manitoba Hydro's
comments submitted in the comment period ending November 18, 2011. Manitoba Hydro does not
believe that the SDT fully addressed our concerns in their responses to our comments in that
commenting period.
Individual
Thad Ness
American Electric Power
Yes
Yes
While we support changing the standard requirements as proposed, AEP offers the following
comments and suggestions. While the implementation plans states that “there was no reliability gap
in the previous version of the standard”, the previous version of the standard, if applied literally, does
indeed contain a reliability gap in that it does not require Generation Owners that own a transmission
Protection System to have a Protection System maintenance and testing program. It is AEP’s
understanding that referring to the proposed revision as “PRC-005-1.1a” implies errata from PRC005-1a, and the announcement refers to “very limited revisions”. If there is indeed a gap of
responsibility in this standard, any changes to remediate such a gap would not be errata, regardless
of the amount of proposed changes in content. As such, we recommend that the drafting team use a
full revision naming convention for these proposed changes, i.e. PRC-005-2. In addition, making
these changes immediately effective would allow no opportunity for an entity to take the proper steps
to become compliant. We believe the revision should include an implementation plan that allows
industry adequate time to analyze their system and complete any additionally required maintenance
and testing activities.
Group
Dominion- NERC Compliance Policy
Mike Garton
Dominion
Yes
No
Group
ACES Power Marketing Standards Collaborators
Jean Nitz
ACES Power Marketing
Yes
Yes
The Implementation Plan for PRC-005-1.1a should be updated to reflect the retirement of currently
effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b became effective on March 14, 2012
replacing PRC-005-1a.
Individual
Darryl Curtis
Oncor Electric Delivery Company
Yes
No
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07: PRC-005-1.1a
The GOTO Drafting Team thanks all commenters who submitted comments on the first formal posting
for PRC-005-1.1a, part of Project 2010-07—Generator Requirements at the Transmission Interface.
Overwhelmingly, commenters approved the standard as written, and the team appreciates that
support. These standards were posted for a 45-day public comment period from March 2, 2012
through April 16, 2012. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 19 sets of comments, including
comments from approximately 65 different people from approximately 38 companies representing 9 of
the 10 Industry Segments as shown in the table on the following pages.
A few commenters did not support the use of the term
“generator interconnection Facility” without a formal
definition. Based on comments received elsewhere in this
project, the SDT has avoided the creation of new NERC
glossary terms, and has received significant industry
support for that strategy. While it is possible that other
language could have been used, the SDT believes the
reference “generator interconnection Facility” is clear.
Note: PRC-005-1b was approved by
FERC on March 14, 2012. Thus, the
changes the SDT proposes will be
applied to that version of the
standard. To reduce confusion, the
SDT’s modified standard is still
referred to as PRC-005-1.1a below,
but all other documents going
forward will be appropriately
updated to reference PRC-005-1.1b
and incorporate the associated
interpretation.
Some commenters are concerned about the changes
proposed in PRC-005-1.1a given the fact that PRC-005-2 is
also being revised. PRC-005-2 does not have the same
issues as PRC-005-1, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of Trustees, the SDT
wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard.
That portion of the standard was modified by NERC staff during the quality review to add boilerplate
compliance language recently approved by NERC legal staff. Modifying it further is outside the scope of
this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing
PRC-005-1a. As noted in the text box above, going forward, all references to PRC-005-1.1a will be
changed to refer to PRC-005-1.1b.
Some commenters stated that the addition of “generator interconnection Facility” was unnecessary
because that Facility is already considered part of the Generator Owner’s assets. While the SDT
believes that Generator Owners do treat the generator interconnection Facility as one of their assets,
commenters in previous postings suggested that adding “generator interconnection Facility” could add
clarity to the specific language in PRC-004 and PRC-005. It was pointed out to the SDT that language in
the requirements of PRC-004 and PRC-005 differed from PRC-001-1, so if the requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only
responsible for analyzing its generator Protection Systems, exclusive of its generator interconnection
Facility Protection Systems under PRC-004 and PRC-005 (whereas this interpretation wasn’t a risk
under PRC-001).
PRC-001-1 used language that had more a more broad application as noted below:
• R1 – “…shall be familiar with the purpose and limitations of protection system schemes applied
in its area.”
• R2 – “…shall notify reliability entities of relay or equipment failures as follows...”
• R3 “…shall coordinate new protective systems and changes as follows…”
PRC-004-2a and PRC-005-1b originally used language which could be construed as being more
restrictive (as shown below):
• PRC-004-2a@R2 – “The Generator Owner shall analyze its generator Protection System
Misoperations...”
• PRC-005-1b@R1 – “…each Generator Owner that owns a generation Protection System…”
• PRC-005-1b@R2 – “…each Generator Owner that owns a generation Protection System…”
The SDT agreed with the comments and modified the standards accordingly.
Other minority comments are addressed alongside their specific comments below.
The SDT considered all stakeholder comments submitted and determined that, save for the update to
reference PRC-005-1.1b instead of PRC-005-1.1a, no additional changes are necessary. The standard
will be posted for a recirculation ballot.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection
Facility” in Requirements R1 and R2 of PRC-005-1.1a. While there was no reliability gap in the
previous version of the standard, if the Requirements were applied literally, there was the
possibility for the misperception that the Generator Owner was only responsible for analyzing its
generator Protection Systems, exclusive of its generator interconnection Facility Protection
Systems. The clarifying changes to R1 and R2 make clear that generator interconnection Facilities
are also part of Generator Owners’ responsibility in the context of this standard. Do you support
the addition of the phrase “or generator interconnection Facility” to accomplish this clarification?
…. ......................................................................................................................................................... 9
2.
Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 13
Consideration of Comments: Project 2010-07 PRC-005-1.1a
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Jesus Sammy Alcaraz
Imperial Irrigation District (IID)
Additional Member Additional Organization Region Segment Selection
1. Jose Landeros
IID
WECC 1, 3, 4, 5, 6
2. Epi Martinez
IID
WECC 1, 3, 4, 5, 6
2.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
X
2
3
X
4
X
5
X
6
X
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6.
Mike Garton
Dominion Resources Services, Inc.
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
NPCC 1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc.
Group
Additional Member Additional Organization
Region
5
6
7
X
X
X
X
X
Segment Selection
1.
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
4
3
Southwest Power Pool Standards
Development Team
Jonathan Hayes
3
NPCC 5
10. Michael R. Lombardi Northeast Utilities
3.
2
Consideration of Comments: Project 2010-07 PRC-005-1.1a
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Dean
5.
Bender
Group
WECC 1
Mike Garton
Dominion- NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
6
2. Louis Slade
NERC Compliance Policy SERC
5
3. Michael Crowley
Electric Transmission
SERC
1, 3
4. Sean Iseminger
Fossil & Hydro
SERC
6
5. Chip Humphrey
Fossil & Hydro
NPCC 6
6. Jeff Bailey
Nuclear
MRO
6.
Group
Jean Nitz
Additional Member
6
ACES Power Marketing Standards
Collaborators
Additional Organization
X
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power, Inc
2. Scott Brame
North Carolina Electric Membership Corporation SERC
RFC
1, 3, 4, 5
3. Clem Cassmeyer
Western Farmers Electric Cooperative
1, 5
SPP
7.
Individual
Keira Kazmerski
Xcel Energy
8.
Individual
Dan Roethemeyer
Dynegy Inc.
9.
Individual
John Bee
Exelon
10.
Individual
Art Salander
HindlePower, Inc
11.
Individual
John Seelke
Individual
13. Individual
14.
3, 4
X
X
X
X
X
Public Service Enterprise Group
X
X
X
X
Martin Kaufman
Michelle R D'Antuono
ExxonMobil Research and Engineering
Ingleside Cogeneration LP
X
Individual
Dale Fredrickson
We Energies
15.
Individual
Michael Falvo
Independent Electricity System Operator
16.
Individual
Joe Petaski
Manitoba Hydro
12.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17.
18.
Individual
Individual
19. Individual
Thad Ness
American Electric Power
X
Darryl Curtis
Will Smith
Oncor Electric Delivery Company
MRO NSRF
X
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
3
X
4
5
X
6
7
X
8
8
9
10
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection Facility” in Requirements R1 and
R2 of PRC-005-1.1a. While there was no reliability gap in the previous version of the standard, if the Requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only responsible for analyzing
its generator Protection Systems, exclusive of its generator interconnection Facility Protection Systems. The clarifying
changes to R1 and R2 make clear that generator interconnection Facilities are also part of Generator Owners’ responsibility in
the context of this standard. Do you support the addition of the phrase “or generator interconnection Facility” to accomplish
this clarification?
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Over 90% of commenters
approved the standard as written, and the team appreciates that support.
A few commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility is clear, and no changes were made.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary and complicates the
ongoing development of PRC-005-2. The SDT believes that the clarifying language is necessary, and points out that if PRC005-1.1a proceeds to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because
the drafting team working on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended
March 28, 2012.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and incorporated that language prior to the last posting.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
9
Organization
Southwest Power Pool Standards
Development Team
Yes or No
Question 1 Comment
No
We would advise the Drafting team to take a look at the FERC OATT to
reconcile the term “generator interconnection facility “with Tariff term for
the LGIA. This should clarify the point of delineation and there should be no
misconception of the language as written.
Response: Thank you for the comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new terms. No change made.
Xcel Energy
No
Xcel Energy does not believe that trying to implement a revision of PRC-0051 at this point improves the reliability of the grid. There are better means of
clarifying the perceived “misperceptions” than drafting a standard revision.
This is particularly the case when PRC-005-2 is further along in the process
and is also posted for industry comment and ballot. The effort of the GOTO
SDT is counterproductive.
Response: Thank you for your comment. The SDT revised the standard based upon comments it received suggesting that it do so.
We do agree that there may have been alternative means to address the issue, such as a request for interpretation or CAN, but
given this was in the scope of the SAR, the SDT modified the standard to add the clarity recommended. If PRC-005-1.1a proceeds
to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because the drafting team working
on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended March 28, 2012.
ExxonMobil Research and
Engineering
No
The bulk electric system is contiguous. Therefore, any facility owned by the
Generator Owner that is used to connect the Generator Owner’s generation
facilities to the bulk electric system is already considered a bulk electric
system asset and part of the Generator Owner’s generation facilities. As
stated by in the question above, the addition of the term “or generator
interconnection Facility” does not resolve a reliability gap or add any
substance to the requirement
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
Consideration of Comments: Project 2010-07 PRC-005-1.1a
10
Organization
Yes or No
Question 1 Comment
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Kansas City Power & Light (Note:
Comment was manually added)
No
The phrase “generator interconnection” facility lacks definition making it
difficult to comment on the proposed change. It is important for the
standards and requirements to clearly delineate, define, or identify the
facilities or operating condition subject to application of the standards and
requirements.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation
of new terms. No change made.
Ingleside Cogeneration LP
Yes
Since PRC-005-1 already requires the Generation Owner to maintain and
test all their BES Protection System components, it seems to Ingleside
Cogeneration LP that the need to specify those which may trip the
interconnection facility as redundant. However, we do not believe that the
Standard Development Team’s modifications materially change the intent of
the Standard - nor can they lead an audit team to assign a double violation
for a single incidence of non-compliance.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Imperial Irrigation District (IID)
Yes
Northeast Power Coordinating
Council
Yes
Imperial Irrigation District (IID)
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
11
Organization
Yes or No
Bonneville Power Administration
Yes
Dominion- NERC Compliance Policy
Yes
ACES Power Marketing Standards
Collaborators
Yes
Dynegy Inc.
Yes
HindlePower, Inc
Yes
Public Service Enterprise Group
Yes
We Energies
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
American Electric Power
Yes
Oncor Electric Delivery Company
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
Question 1 Comment
12
2.
Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Overwhelmingly,
commenters approved of the standard as written, and the team appreciates that support.
Some commenters are concerned about the changes proposed in PRC-005-1.1a given the fact that PRC-005-2 is also
being revised. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are needed to that
standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of
Trustees, the SDT wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard. That portion of the
standard was modified by NERC staff during the quality review to add boilerplate compliance language recently approved
by NERC legal staff. Modifying it further is outside the scope of this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing PRC-005-1a. Going
forward, all references to PRC-005-1.1a will be changed to refer to PRC-005-1.1b.
Some commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility” is clear, and no changes were made.
One commenter was concerned that the addressing of a literal “reliability gap” should not be considered an errata
change. The SDT maintains that there is no actual reliability gap in the current standard language – just the possible
perception of one. The SDT and most stakeholders still believe that the clarifying change is a useful one, but it is
appropriate to classify as a minor change because it does not change the scope or intent of the associated standard. Still,
the SDT agrees that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to
its changes as errata.
One commenter was concerned that the standard as written does not allow for alternative testing programs in cases
where testing programs do not follow the ownership of the equipment. The SDT points out that an entity can enter into
an agreement (including a Coordinated Functional Registration) whereby another entity is assigned responsibility for
compliance with one or more requirements of one or more reliability standards without the standard itself being so
modified. The SDT therefore does not agree that this standard should be explicitly modified to allow what the commenter
suggests.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
13
One commenter was concerned about the statement that “no changes” were made to the VSLs. Because the SDT has not
proposed changes that affect the scope or intent of the current standard, no changes to the VSLs were necessary. The
same VSLs that have been approved by FERC (which can be found in the VSL matrix posted on NERC’s website:
http://www.nerc.com/page.php?cid=2|20|288) will remain in effect.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and modified the standards accordingly.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previously
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
One commenter encouraged the SDT to update the Effective Dates and Implementation Dates language to incorporate
the latest NERC legal boilerplate language. That change has been made.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Organization
Yes or No
Baltimore Gas & Electric
Company
Southwest Power Pool
Standards Development Team
Abstain
Yes
Question 2 Comment
Please refer to comments submitted by Exelon.
This effort seems to be redundant due to the work going on with PRC-005-2. We do
not understand why this change is being made and it wasn’t made very clear in the
red line changes or in this comment form background.
Response: Thank you for your comment. The Project 2007-17 Protection System Maintenance and Testing SDT is working on
comprehensive changes to PRC-005, as described in detail in the SAR posted on that projects webpage, while the Project 2010-07
Consideration of Comments: Project 2010-07 PRC-005-1.1a
14
Organization
Yes or No
Question 2 Comment
Generator Requirements at the Transmission Interface SDT is focused on making surgical revisions to standards where there might be
a reliability gap related to generator-owned Transmission Facilities. The current draft of PRC-005-2 does not have the same issues as
PRC-005-1 with respect to generator-owned Facilities, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT, the Project 2010-07 SDT wants to ensure that the
generator interconnection Facility is covered.
Bonneville Power
Administration
Yes
Regarding Section 1.3 Data Retention, BPA believes that it would be difficult for an
entity to provide “other evidence” to demonstrate compliance when the data
retention period is shorter than the time since the last audit. BPA requests the
drafting team to offer guidance as to what "other evidence" could be provided other
than what is already described in the measures. BPA believes that suggesting there
is some “other evidence” without providing a description leaves the TO’s and GO’s
without clear direction on how to comply with the standard. BPA suggests the data
retention period should be three years or since the time the last audit occurred,
whichever is longer for each TO and GO to retain evidence.Should the drafting team
revise the Data Retention language to reflect BPA’s concerns, BPA would vote in
favor of PRC-005-1.1a.
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
ACES Power Marketing
Standards Collaborators
Yes
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Exelon
Yes
The standard language should be clarified to allow for alternative testing programs,
agreed upon by both TO and GO, in cases where testing programs do not follow
ownership of the equipment for all Component Types so long as all of the protection
for the generator interconnection facility is covered.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
15
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. An entity can enter into an agreement (including a Coordinated Functional Registratyion)
whereby another entity is assigned responsibility for compliance with one or more requirements of one or more reliability standards
without the standard itself being so modified. The SDT therefore does not agree that this standard should be explicitly modified to
allow this. No change made.
ExxonMobil Research and
Engineering
Yes
The SDT has utilized two terms in this round of the drafting process whose
definitions are subject to interpretation. The terms ‘generating station switchyard’
and ‘generator interconnection Facility’ need to be defined to prevent inconsistent
enforcement or need for the development of a Compliance Application Notice. As
referenced in our comments to FAC-003-X/3, when you try to apply the term
‘generating station switchyard’ to an industrial complex that contains multiple
substations between the GSU and utility interconnection facility (another substation)
in order to measure the generator lead line for the 1 mile quota, there are several
candidates that appear to fit the criteria.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. While the SDT concedes there may be other language that could be used, the language posted has wide
industry support, therefore no change will be made.
American Electric Power
Yes
While we support changing the standard requirements as proposed, AEP offers the
following comments and suggestions.While the implementation plans states that
“there was no reliability gap in the previous version of the standard”, the previous
version of the standard, if applied literally, does indeed contain a reliability gap in
that it does not require Generation Owners that own a transmission Protection
System to have a Protection System maintenance and testing program. It is AEP’s
understanding that referring to the proposed revision as “PRC-005-1.1a” implies
errata from PRC-005-1a, and the announcement refers to “very limited revisions”. If
there is indeed a gap of responsibility in this standard, any changes to remediate
such a gap would not be errata, regardless of the amount of proposed changes in
content. As such, we recommend that the drafting team use a full revision naming
Consideration of Comments: Project 2010-07 PRC-005-1.1a
16
Organization
Yes or No
Question 2 Comment
convention for these proposed changes, i.e. PRC-005-2.In addition, making these
changes immediately effective would allow no opportunity for an entity to take the
proper steps to become compliant. We believe the revision should include an
implementation plan that allows industry adequate time to analyze their system and
complete any additionally required maintenance and testing activities.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is a useful one, but it is appropriate to classify as a
minor change because it does not change the scope or intent of the associated standard. Regarding the naming convention, the SDT
was advised that the errata naming convention would be acceptable to avoid confusion with the more complete set of revisions to
PRC-005 that are underway in Project 2007-17. The SDT had previously used the word “errata” to describe its changes, but agrees
that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to its changes as errata. No
change made.
Southern Illinois Power Coop.,
Brazos Electric Power
Cooperative, Inc.
Affirmative
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Pacific Gas and Electric
Company
Affirmative
The data retention period identified in D1.3 cannot be shorter than the time
between audits or the prior maintenance and testing interval
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
AEP Service Corp., AEP and
AEP Marketing, American
Electric Power
Affirmative
Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power
Consideration of Comments: Project 2010-07 PRC-005-1.1a
17
Organization
Yes or No
Question 2 Comment
Great River Energy
Affirmative
Great River Energy agrees with the comments of the MRO NSRF.
Dairyland Power Coop.
Affirmative
Please see comments submitted by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review Forum
Madison Gas and Electric Co.
Affirmative
Please see MRO NSRF comments.
Omaha Public Power District
Affirmative
Please see MRO NSRF Comments.
Brazos Electric Power
Cooperative, Inc.
Affirmative
See ACES Power Marketing comments.
Occidental Chemical
Affirmative
See comments submitted by Ingleside Cogeneration LP
Central Electric Power
Cooperative
Affirmative
See Matt Pacobit's comments from AECI
Southern Company Services,
Inc.
Affirmative
None
Alabama Power Company
Affirmative
None
Georgia Power Company
Affirmative
None
Gulf Power Company
Affirmative
None
Mississippi Power
Affirmative
None
Southern Company
Generation and Energy
Affirmative
None
Consideration of Comments: Project 2010-07 PRC-005-1.1a
18
Organization
Yes or No
Question 2 Comment
Marketing
Beaches Energy Services
Affirmative
Independent Electricity
System Operator
(No Comments.)
The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 of the draft standard and P. 1
of the Implementation Plan, to the following effect:”, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.”
Response: Thank you for your comment. The language you cite has been approved by NERC legal and has been updated in the
Effective Dates section and in the Implementation Plan.
Sunflower Electric Power
Corporation
Negative
A new term is introduced that is not a NERC defined term, the term is generator
interconnection Facility. The term was inserted without comment and clearly is
intended to include something that is not covered by the Standard. This new term
should be removed or defined in Glossary of Terms so entities may understand just
what is covered by this new term. The Implementation Plan for PRC-005-1.1a should
be updated to reflect the retirement of currently effective PRC-005-1b instead of
PRC-005-1a. PRC-005-1b became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. The SDT purposefully did not create a new term (note that only Facility is capitalized, while generator and
interconnection are not). No change made.
Seminole Electric Cooperative,
Inc.
Negative
a) Section D.2 Violation Severity Levels (no changes) - The standard should stand on
its own, therefore, just stating that the VSLs have "(no changes") is incomplete and
will lead to confusion. Please provide definition and clarity to this section.
Response: Thank you for your comment. The SDT has not proposed changes that affect the scope or intent of the current standard,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
19
Organization
Yes or No
Question 2 Comment
and because of that, no changes to the VSLs are necessary. The same VSLs that have been approved by FERC (which can be found in
the VSL matrix posted on NERC’s website: http://www.nerc.com/page.php?cid=2|20|288) will remain in effect. No change made.
Austin Energy, City of Austin
dba Austin Energy
Negative
Adding the words "generator interconnection" to the Facility description does not
add clarity to the Standard. PRC-005-1 is clear as written, indicating the actual owner
of a device supporting the BES is responsible for performing the actions necessary to
comply with PRC-005. The term "generator interconnection" is not defined and
introduces confusion, making responsibility for the application of the Requirements
less clear.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is useful. No change made.
Kansas City Power & Light Co.
Negative
Concerns have been expressed in the Standard comment forms provided by NERC.
Tucson Electric Power Co.
Negative
It would be difficult for an entity to provide "other evidence" to demonstrate
compliance when the data retention period is shorter than the time since the last
audit. Suggest that the data retention period language should be modified to "three
years or since the time the last audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
Bonneville Power
Administration
Negative
Please refer to BPA's comments submitted separately.
Manitoba Hydro
Negative
Please see comments submitted by Joe Petaski (Manitoba Hydro)
Xcel Energy, Inc.
Negative
Xcel Energy sees this project as counter-productive to the efforts of the Protection
Consideration of Comments: Project 2010-07 PRC-005-1.1a
20
Organization
Yes or No
Question 2 Comment
System Maintenance and Testing Standard Drafting Team that currently has PRC005-2 posted for comment and successive ballot.
Response: Thank you for your comment. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are
needed to that standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT,
we want to ensure that the generator interconnection Facility is covered.
City and County of San
Francisco
Negative
This revision should be used as an opportunity to clean up language relating to the
data retention period for PRC-005. The following language has been suggested and
appears consistent with the actual data retention period needed for all functional
registrations encompassed by this Standard: "three years or since the time the last
audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Other changes are outside the scope of the SDT.
HindlePower, Inc
No
I beleive that the requirments as shown in 1-4a - c need to be better clarified as to
the actual tasks required. There seems to be no real distinction between Verification
and inspection. There is no clear reporting structure and the requirment to
substitute Ohmic readings vs. discharge test is not basede on any industry reliable
standards. since there is much debate in the industry as to the validity if Ohmic
testing and it has not been accepted by the IEEE as an acceptbale practice I would
rather see terms in line with either IEEE standard or manufacvturer's
recommendations.
Response: Thank you for your comment. The SDT believes these comments may have been intended for the Project 2007-17 drafting
team which is making comprehensive revisions to PRC-005-2. The comment will be forwarded to that team by NERC staff.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project2010-07 in
general. If a Generator Owner is required to register as a TO, all theRequirements
applicable to a TO should apply. There is no need to changespecific Reliability
Consideration of Comments: Project 2010-07 PRC-005-1.1a
21
Organization
Yes or No
Question 2 Comment
Standards to allow the Generator Owner to perform onlyselected TO functions.For
additional information, please see Manitoba Hydro's commentssubmitted in the
comment period ending November 18, 2011. Manitoba Hydrodoes not believe that
the SDT fully addressed our concerns in their responsesto our comments in that
commenting period.
Response: Thank you for your comment. The SDT must act within the scope of the SAR for this project. The comments appear to
indicate that the entity disagrees with the SAR although they cite the Technical Justification document. The Technical Justification
document is meant to be used to show how the SDT arrived at its decisions to revise only 4 reliability standards as opposed to all that
were originally include in the Ad Hoc report, or those in the cited FERC orders.
MRO NSRF
Section D, Article 1.3 Data Retention states that the entities retain evidence for the
entire audit period since the last audit. Furthermore, in the 2nd paragraph of Article
1.3, it states that an entity “shall retail evidence of the implementation of its
Protection System maintenance and testing program for three years.”
If an entity is to prove compliance related to R2.1 and R2.2 of PRC-005-1.1a, the
NSRF recommends that Evidence Retention be revised to state “the two most
recent performance of each distinct maintenance activity for the Protection System
Components, or all performances of each distinct maintenance activity for the
Protection System Component since the previous scheduled audit date, whichever is
longer.”This agrees with the current draft in progress for PRC-005-2 Section D,
Compliance, Article 1.3, paragraph 4.
The NSRF is also concerned with those testing intervals, such as 12 years, which
would dictate a Registered Entity maintain 24 years of records, which is
unreasonable. This should be revised to have documentation for the most current
one testing interval, if after 06/18/07.
The NSRF believes that “the term “generation” in R1 and R2 should be changed to
“generator”. If changed, both Measures will need to be updated as well.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
22
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The Data Retention section was revised by NERC staff to add boilerplate compliance
language approved elsewhere. Thus, it is outside the scope of the SDT and no change was made.
In R1 and R2, the reference to “generation” was in the original standard, referring to a generation Protection System. While
“generator” may work better here, it is not within the scope of the 2010-07 SDT to change language outside the surgical insertion of
“generator interconnection Facility.”
Oncor Electric Delivery
Company
No
Imperial Irrigation District (IID)
No
Northeast Power Coordinating
Council
No
Imperial Irrigation District (IID)
No
Dominion- NERC Compliance
Policy
No
Xcel Energy
No
Dynegy Inc.
No
Public Service Enterprise
Group
No
Ingleside Cogeneration LP
No
Consideration of Comments: Project 2010-07 PRC-005-1.1a
23
Organization
Yes or No
We Energies
No
Question 2 Comment
END OF REPORT
Consideration of Comments: Project 2010-07 PRC-005-1.1a
24
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
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Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by the
NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume that FAC003-2 will be approved by FERC and other governmental authorities. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, FAC-003-1, the current
FERC-approved version of the standard, and one to FAC-003-2, the version developed by the Project
2007-07 team and adopted by NERC’s Board of Trustees.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
4.1. Applicable Transmission Owner
4.1.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.2. Applicable Generator Owner
4.2.1. Generator Owner that owns an overhead transmission line(s) that (1) extends
greater than one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight 1 from
the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any
lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
1
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
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Standard FAC-003-X — Transmission Vegetation Management Program
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 2.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
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Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
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Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
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Standard FAC-003-X — Transmission Vegetation Management Program
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
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Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
7 of 12
Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
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Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
qualifications and
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Draft 3: March 6, 2012
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
qualifications and
Standard FAC-003-X — Transmission Vegetation Management Program
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
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Draft 3: March 6, 2012
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
Standard FAC-003-X — Transmission Vegetation Management Program
R3
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
N/A
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
11 of 12
Draft 3: March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
12 of 12
Draft 3: March 6, 2012
Revision under Project
2010-07
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 12
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Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by the
NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume that FAC003-2 will be approved by FERC and other governmental authorities. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, FAC-003-1, the current
FERC-approved version of the standard, and one to FAC-003-2, the version developed by the Project
2007-07 team and adopted by NERC’s Board of Trustees.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its final
stages, but the Project 2010-07 drafting team does not want to assume that the project will be
approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07 drafting team has
develop two sets of proposed changes: one to this version, FAC-003-1, the current FERC-approved
version of the standard, and one to FAC-003-2, the latest draft of Version 2 as proposed by the Project
2007-07 team
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely proceed
with the modifications it has proposed in the redline to that version of the standard. These changes
would be submitted for stakeholder approval and balloted as FAC-003-3. FAC-003-2 would be retired
once FAC-003-03 was approved.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will proceed
with the changes to FAC-003-1 seen below to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability section, modifications
to the NERC defined terms Right-of-Way to include Generator Owners, and some formatting changes
to bring the standard up to date. These changes would not be comprehensive; rather, they would aim
to include the generator interconnection Facility in the standard with as few other changes as possible.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rights-of-way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
(NERC).
Applicability:
4.1. Regional Entity.
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the RE as critical
to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an overhead transmission line(s) that (1) extends
greater than one mile or 1.609 kilometers beyond the fenced area of the
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Standard FAC-003-X — Transmission Vegetation Management Program
generating station switchyard up to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight 1 from
the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any
lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees adoption.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 2.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
1
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 23: August 31, 2011March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
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Standard FAC-003-X — Transmission Vegetation Management Program
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
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Draft 23: August 31, 2011March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
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Draft 23: August 31, 2011March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
7 of 12
Draft 23: August 31, 2011March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity did not
include and keep current one
of the four required elements
of its TVMP, as directed by
the requirement.
N/A
The responsible entity did not
include and keep current two
of the four required elements
of its TVMP, as directed by
the requirement.
N/A
N/A
N/A
The responsible entity did not
include and keep current three
of the four required elements
of its TVMP, as directed by
the requirement.
The applicable entity TVMP
did not define a schedule, as
directed by the requirement, or
the type of ROW vegetation
inspections, as directed by the
requirement.
N/A
The responsible entity did not
include and keep current all
required elements of the
TVMP, as directed by the
requirement.
The applicable entity TVMP
did not define a schedule, as
directed by the requirement,
nor the type of ROW
vegetation inspections, as
directed by the requirement.
The responsible entity, in its
TVMP, failed to identify and
document clearances between
vegetation and any overhead,
ungrounded supply
conductors.
OR
The responsible entity, in its
TVMP, failed to take into
consideration transmission
line voltage, or the effects of
ambient temperature on
conductor sag under
maximum design loading, or
the effects of wind velocities
on conductor sway.
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Draft 23: August 31, 2011March 6, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
OR
R1.2.1
N/A
N/A
N/A
The responsible entity, in its
TVMP, failed to establish
Clearance 1 or Clearance 2
values.
The responsible entity failed
to determine and document an
appropriate clearance distance
to be achieved at the time of
transmission vegetation
management work taking into
account local conditions and
the expected time frame in
which the responsible entity
expects to return for future
vegetation management work.
OR
R1.2.2
R1.2.2.1
N/A
N/A
N/A
N/A
N/A
N/A
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Draft 23: August 31, 2011March 6, 2012
The responsible entity
documented a Clearance 1
value that was smaller than its
Clearance 2 value.
The responsible entity failed
to determine and document
Clearance 2 values taking into
account local conditions and
the expected time frame in
which the responsible entity
expects to return for future
vegetation management work.
Where transmission system
transient overvoltage factors
were known, clearances were
not derived from Table 5,
Standard FAC-003-X — Transmission Vegetation Management Program
R1.2.2.2
R1.3
R1.4
N/A
N/A
N/A
For responsible entities
directly involving fewer than
20 persons in the design and
implementation of the TVMP,
one of those persons did not
hold appropriate qualifications
and training to perform their
duties. For responsible entities
directly involving 20 or more
persons in the design and
implementation of the TVMP,
5% or less of those persons
did not hold appropriate
qualifications and training to
perform their duties.
For responsible entities
directly involving fewer than
20 persons in the design and
implementation of the TVMP,
two of those persons did not
hold appropriate qualifications
and training to perform their
duties. For responsible entities
directly involving 20 or more
persons in the design and
implementation of the TVMP,
more than 5% up to (and
including) 10%of those
persons did not hold
appropriate qualifications and
training to perform their
duties.
N/A
For responsible entities
directly involving fewer than
20 persons in the design and
implementation of the TVMP,
three of those persons did not
hold appropriate qualifications
and training to perform their
duties. For responsible entities
directly involving 20 or more
persons in the design and
implementation of the TVMP,
more than 10% up to (and
including) 15%of those
persons did not hold
appropriate qualifications and
training to perform their
duties.
N/A
N/A
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Draft 23: August 31, 2011March 6, 2012
IEEE 516-2003, phase-tophase voltages, with
appropriate altitude correction
factors applied.
Where transmission system
transient overvoltage factors
are known, clearances were
not derived from Table 7,
IEEE 516-2003, phase-tophase voltages, with
appropriate altitude correction
factors applied.
For responsible entities
directly involving fewer than
20 persons in the design and
implementation of the TVMP,
more than three of those
persons did not hold
appropriate qualifications and
training to perform their
duties. For responsible entities
directly involving 20 or more
persons in the design and
implementation of the TVMP,
more than 15% of those
persons did not hold
appropriate qualifications and
training to perform their
duties.
The responsible entity's
TVMP does not include
mitigation measures to
achieve sufficient clearances
where restrictions to the ROW
are in effect.
Standard FAC-003-X — Transmission Vegetation Management Program
R1.5
R2
R3
R4
N/A
N/A
N/A
The responsible entity did not
meet one of the three required
elements (including in the
annual plan a description of
methods used for vegetation
management, maintaining
documentation of adjustments
to the annual plan, or having
systems and procedures for
tracking work performed as
part of the annual plan)
specified in the requirement.
The responsible entity did not
meet two of the three required
elements (including in the
annual plan a description of
methods used for vegetation
management, maintaining
documentation of adjustments
to the annual plan, or having
systems and procedures for
tracking work performed as
part of the annual plan)
specified in the requirement.
The responsible entity did not
meet the three required
elements (including in the
annual plan a description of
methods used for vegetation
management, maintaining
documentation of adjustments
to the annual plan, or having
systems and procedures for
tracking work performed as
part of the annual plan)
specified in the requirement.
The responsible entity failed
to provide a quarterly outage
report, but did not experience
any reportable outages.
The responsible entity
provided a quarterly report,
but failed to include
information required by R3.3.
The responsible entity
provided a quarterly outage
report, but failed to include a
reportable Category 3 outage
as described in R3.4.3.
The responsible entity did not
establish or did not document
a process for the immediate
communication of vegetation
conditions that present an
imminent threat of line outage,
as directed by the requirement.
The responsible entity does
not have an annual plan for
vegetation management.
OR
The responsible entity has not
implemented the annual plan
for vegetation management.
The responsible entity
experienced reportable
outages but failed to provide a
quarterly report.
OR
OR
The responsible entity
provided a quarterly report,
but failed to report in the
manner specified by one or
more of the following
subcomponents of
Requirement R3: R3.1 or
R3.2.
The responsible entity
provided a quarterly outage
report, but failed to include a
reportable Category 1 (as
described in R3.4.1) or
Category 2 outage (as
described in R3.4.2).
N/A
N/A
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Draft 23: August 31, 2011March 6, 2012
N/A
N/A
Standard FAC-003-X — Transmission Vegetation Management Program
E.
Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
May 16, 2011
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date
12 of 12
Draft 23: August 31, 2011March 6, 2012
Revision under Project
2010-07
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 3: March 6, 2012
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 3: March 6, 2012
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
2
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 3: March 6, 2012
3
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by
the NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume
that FAC-003-2 will be approved by FERC and other governmental authorities. Thus, the
Project 2010-07 drafting team has developed two sets of proposed changes: one to this version,
FAC-003-2, the version developed by the Project 2007-07 team and adopted by NERC’s Board
of Trustees, and one to FAC-003-1, the current FERC-approved version of the standard.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1 Transmission Owners that own Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own
generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands
owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2. 1 Each overhead transmission line operated
at 200kV or higher.
1
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 3: March 6, 2012
4
FAC-003-3 — Transmission Vegetation Management
4.2.2 Each overhead transmission line operated below 200kV identified as an element
of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3 Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4 Each overhead transmission line identified above (4.2.1 through 4.2.3) located
outside the fenced area of the switchyard, station or substation and any portion of the
span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1 Overhead transmission lines that (1) extend
Standard FAC-003-3, “transmission
line(s) and “applicable line(s) can
greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station
also refer to the generation Facilities
as referenced in 4.3 and its
switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a
subsections.
clear line of sight 3 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Draft 3: March 6, 2012
5
FAC-003-3 — Transmission Vegetation Management
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
Draft 3: March 6, 2012
6
FAC-003-3 — Transmission Vegetation Management
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
•
Performance-based: Requirements 1 and 2
•
Competency-based: Requirement 3
•
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
Draft 3: March 6, 2012
7
FAC-003-3 — Transmission Vegetation Management
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Draft 3: March 6, 2012
8
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 4 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 5,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 6,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
4
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 3: March 6, 2012
9
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 3: March 6, 2012
10
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 3: March 6, 2012
11
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or
Rationale
evidence that the line was de-energized.
Inspections are used by applicable
(R5)
Transmission Owners and applicable
Generator Owners to assess the condition of
the entire ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
R6. Each applicable Transmission Owner and
recently-completed work. This requirement
applicable Generator Owner shall perform
sets a minimum Vegetation Inspection
a Vegetation Inspection of 100% of its
frequency of once per calendar year but
applicable transmission lines (measured in
with no more than 18 months between
units of choice - circuit, pole line, line
inspections on the same ROW. Based upon
miles or kilometers, etc.) at least once per
average growth rates across North America
calendar year and with no more than 18
and on common utility practice, this
calendar months between inspections on
minimum frequency is reasonable.
the same ROW 7 [Violation Risk Factor:
Transmission Owners should consider local
and environmental factors that could
7
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 3: March 6, 2012
12
FAC-003-3 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 8
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
8
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 3: March 6, 2012
13
FAC-003-3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Draft 3: March 6, 2012
14
FAC-003-3 — Transmission Vegetation Management
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
Draft 3: March 6, 2012
15
FAC-003-3 — Transmission Vegetation Management
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 3: March 6, 2012
16
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 3: March 6, 2012
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
17
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
Long-Term
Planning
Real-time
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
Lower
Medium
R5
Operations
Planning
Medium
R6
Operations
Medium
Draft 3: March 6, 2012
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
The responsible entity
The responsible entity failed
The responsible entity failed to
18
The responsible entity failed to
FAC-003-3 — Transmission Vegetation Management
Planning
R7
Operations
Planning
Medium
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 3: March 6, 2012
19
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by an applicable Transmission Owner or applicable Generator Owner from a third party
Draft 3: March 6, 2012
20
FAC-003-3 — Transmission Vegetation Management
such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission Owner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set
forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners may
in some cases own more property or rights than are needed to reliably operate transmission lines.
This modified definition represents a slight but significant departure from the strict legal definition
of “right of way” in that this definition is based on engineering and construction considerations
that establish the width of a corridor from a technical basis. The pre-2007 maintenance records are
included in the revised definition to allow the use of such vegetation widths if there were no
engineering or construction standards that referenced the width of right of way to be maintained
for vegetation on a particular line but the evidence exists in maintenance records for a width that
was in fact maintained prior to this standard becoming mandatory. Such widths may be the only
information available for lines that had limited or no vegetation easement rights and were typically
maintained primarily to ensure public safety. This standard does not require additional easement
rights to be purchased to satisfy a minimum right of way width that did not exist prior to this
standard becoming mandatory.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance
inspections and vegetation inspections to be performed concurrently. This allows potential
efficiencies, especially for those lines with minimal vegetation and/or slow vegetation growth
rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
Draft 3: March 6, 2012
21
FAC-003-3 — Transmission Vegetation Management
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by an applicable Transmission Owner or applicable Generator Owner or Reliability
Coordinator to protect an Interconnection may cause excessive sagging and an outage. Another
example would be ice loading beyond the line’s Rating and Rated Electrical Operating
Condition. Such vegetation-related encroachments and outages are not violations of this
standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
Draft 3: March 6, 2012
22
FAC-003-3 — Transmission Vegetation Management
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of an applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the applicable TO or applicable GO
should use the next largest clearance distance based on the next highest nominal voltage in the
table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, an applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
Draft 3: March 6, 2012
23
FAC-003-3 — Transmission Vegetation Management
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner or applicable Generator Owner employee who
Draft 3: March 6, 2012
24
FAC-003-3 — Transmission Vegetation Management
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
Draft 3: March 6, 2012
25
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
Draft 3: March 6, 2012
26
FAC-003-3 — Transmission Vegetation Management
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies
1,000 miles of applicable transmission lines to be completed in the applicable Transmission
Owner’s or applicable Generator Owner’s annual plan, the applicable Transmission Owner or
applicable Generator Owner will be responsible completing those identified miles. If a
applicable Transmission Owner or applicable Generator Owner makes a modification to the
annual plan that does not put the transmission system at risk of an encroachment the annual plan
may be modified. If 100 miles of the annual plan is deferred until next year the calculation to
determine what percentage was completed for the current year would be: 1000 – 100 (deferred
miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner only completed 875 of the total
1000 miles with no acceptable documentation for modification of the annual plan the calculation
for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete
then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
Draft 3: March 6, 2012
27
FAC-003-3 — Transmission Vegetation Management
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Draft 3: March 6, 2012
28
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 9
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
9
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 3: March 6, 2012
29
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 3: March 6, 2012
30
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Draft 3: March 6, 2012
31
FAC-003-3 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an in-
Draft 3: March 6, 2012
32
FAC-003-3 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Draft 3: March 6, 2012
33
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 3: March 6, 2012
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
34
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees
adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 23: September 29, 2011March 6, 2012
2
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Draft 23: September 29, 2011March 6, 2012
3
FAC-003-3 — Transmission Vegetation Management
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
Draft 23: September 29, 2011March 6, 2012
4
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in
effect when the line was built. The ROW width in no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 23: September 29, 2011March 6, 2012
5
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by
the NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume
that FAC-003-2 will be approved by FERC and other governmental authorities. Thus, the
Project 2010-07 drafting team has developed two sets of proposed changes: one to this version,
FAC-003-2, the version developed by the Project 2007-07 team and adopted by NERC’s Board
of Trustees, and one to FAC-003-1, the current FERC-approved version of the standard.
FAC-003-2 is currently under development under Project 2007-07. The project is nearing its
final stages, but the Project 2010-07 drafting team does not want to assume that the project will
be approved by NERC’s Board or Trustees (BOT) or FERC. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, the latest draft
of Version 2 as proposed by the Project 2007-07 team, and one to FAC-003-1, the current
FERC-approved version of the standard.
If FAC-003-2 is approved by NERC’s BOT, the Project 2010-07 drafting team will likely
proceed with the modifications seen in this standard. These changes would be submitted for
stakeholder approval and balloted as FAC-003-3. Several scenarios that could play out based
on the order of the approval of these versions of the standards are addressed in the FAC-003-3
implementation plan.
If, however, FAC-003-2 remains under development, the Project 2010-07 drafting team will
proceed with changes to FAC-003-1 to avoid further delay of its project goals. Changes to
FAC-003-1 would address the addition of Generator Owners to the applicability, the proposal
of modifications to the NERC defined term Right-of-Way to include applicable Generator
Owners, and some formatting changes to bring the standard up to date. These changes would
not be comprehensive; rather, they would aim to include the generator interconnection Facility
in the standard with as few other changes as possible.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
Draft 23: September 29, 2011March 6, 2012
6
FAC-003-3 — Transmission Vegetation Management
4.1.1.
Applicable Transmission Owners
4.1.1.1.
4.2.
4.1.2.
Transmission Owners that own Transmission Facilities defined in
Applicable Generator Owners
4.1.2.1.
Generator Owners that own generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 1, state,
provincial, public, private, or tribal entities:
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
4.2.1.
Each overhead transmission line
industry for reasons summarized as
operated at 200kV or higher.
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
4.2.2.
Each overhead transmission line
operated below 200kV identified as an
element of an IROL under NERC
Standard FAC-014 by the Planning
Coordinator.
4.2.3.
Each overhead transmission line
operated below 200 kV identified as an
element of a Major WECC Transfer
Path in the Bulk Electric System by
WECC.
4.2.4.
Each overhead transmission line
identified above (4.2.1 through 4.2.3) located outside the fenced area of
the switchyard, station or substation and any portion of the span of the
transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1.
Overhead transmission lines that (1)
Standard FAC-003-3, “transmission
extend greater than one mile or 1.609
line(s) and “applicable line(s) can
kilometers beyond the fenced area of
also refer to the generation Facilities
the generating station switchyard to the
as referenced in 4.3 and its
point of interconnection with a
subsections.
Transmission Owner’s Facility or (2)
do not have a clear line of sight 3 from the generating station switchyard
1
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 23: September 29, 2011March 6, 2012
7
FAC-003-3 — Transmission Vegetation Management
fence to the point of interconnection with a Transmission Owner’s
andFacility and are:
4.3.1.1.
Operated at 200kV or higher; or
4.3.1.2.
Operated below 200kV identified as an element of an IROL under
NERC Standard FAC-014 by the Planning Coordinator; or.
4.3.1.3.
Operated below 200 kV identified as an element of a Major WECC
Transfer Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
5.1.1.
This standard uses three types of requirements to provide layers of
protection to prevent vegetation related outages that could lead to
Cascading:
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Draft 23: September 29, 2011March 6, 2012
8
FAC-003-3 — Transmission Vegetation Management
5.1.2.
a)
Performance-based defines a particular reliability objective or
outcome to be achieved. In its simplest form, a results-based requirement
has four components: who, under what conditions (if any), shall perform
what action, to achieve what particular bulk power system performance
result or outcome?
5.1.3.
b)
Risk-based preventive requirements to reduce the risks of failure
to acceptable tolerance levels. A risk-based reliability requirement should
be framed as: who, under what conditions (if any), shall perform what
action, to achieve what particular result or outcome that reduces a stated
risk to the reliability of the bulk power system?
5.1.4.
c)
Competency-based defines a minimum set of capabilities an
entity needs to have to demonstrate it is able to perform its designated
reliability functions. A competency-based reliability requirement should
be framed as: who, under what conditions (if any), shall have what
capability, to achieve what particular result or outcome to perform an
action to achieve a result or outcome or to reduce a risk to the reliability
of the bulk power system?
5.1.5.
The defense-in-depth strategy for reliability standards development
recognizes that each requirement in a NERC reliability standard has a role
in preventing system failures, and that these roles are complementary and
reinforcing. Reliability standards should not be viewed as a body of
unrelated requirements, but rather should be viewed as part of a portfolio
of requirements designed to achieve an overall defense-in-depth strategy
and comport with the quality objectives of a reliability standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
5.1.6.
For this standard, the requirements have been developed as follows:
5.1.7.
Performance-based: Requirements 1 and 2
Draft 23: September 29, 2011March 6, 2012
9
FAC-003-3 — Transmission Vegetation Management
5.1.8.
Competency-based: Requirement 3
5.1.9.
Risk-based: Requirements 4, 5, 6 and 7
5.1.10.
R3 serves as the first line of defense by ensuring that entities understand
the problem they are trying to manage and have fully developed strategies
and plans to manage the problem. R1, R2, and R7 serve as the second line
of defense by requiring that entities carry out their plans and manage
vegetation. R6, which requires inspections, may be either a part of the
first line of defense (as input into the strategies and plans) or as a third line
of defense (as a check of the first and second lines of defense). R4 serves
as the final line of defense, as it addresses cases in which all the other lines
of defense have failed.
5.1.11.
Major outages and operational problems have resulted from interference
between overgrown vegetation and transmission lines located on many
types of lands and ownership situations. Adherence to the standard
requirements for applicable lines on any kind of land or easement, whether
they are Federal Lands, state or provincial lands, public or private lands,
franchises, easements or lands owned in fee, will reduce and manage this
risk. For the purpose of the standard the term “public lands” includes
municipal lands, village lands, city lands, and a host of other governmental
entities.
5.1.12.
This standard addresses vegetation management along applicable
overhead lines and does not apply to underground lines, submarine lines or
to line sections inside an electric station boundary.
5.1.13.
This standard focuses on transmission lines to prevent those vegetation
related outages that could lead to Cascading. It is not intended to prevent
customer outages due to tree contact with lower voltage distribution
system lines. For example, localized customer service might be disrupted
if vegetation were to make contact with a 69kV transmission line
supplying power to a 12kV distribution station. However, this standard is
not written to address such isolated situations which have little impact on
the overall electric transmission system.
5.1.14.
Since vegetation growth is constant and always present, unmanaged
vegetation poses an increased outage risk, especially when numerous
transmission lines are operating at or near their Rating. This can present a
significant risk of consecutive line failures when lines are experiencing
large sags thereby leading to Cascading. Once the first line fails the shift
of the current to the other lines and/or the increasing system loads will
lead to the second and subsequent line failures as contact to the vegetation
under those lines occurs. Conversely, most other outage causes (such as
trees falling into lines, lightning, animals, motor vehicles, etc.) are not an
interrelated function of the shift of currents or the increasing system
Draft 23: September 29, 2011March 6, 2012
10
FAC-003-3 — Transmission Vegetation Management
loading. These events are not any more likely to occur during heavy
system loads than any other time. There is no cause-effect relationship
which creates the probability of simultaneous occurrence of other such
events. Therefore these types of events are highly unlikely to cause largescale grid failures. Thus, this standard places the highest priority on the
management of vegetation to prevent vegetation grow-ins.
Draft 23: September 29, 2011March 6, 2012
11
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 4 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 5,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 6,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
4
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 23: September 29, 2011March 6, 2012
12
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 23: September 29, 2011March 6, 2012
13
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 23: September 29, 2011March 6, 2012
14
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or
Rationale
evidence that the line was de-energized.
Inspections are used by applicable
(R5)
Transmission Owners and applicable
Generator Owners to assess the condition of
the entire ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
R6. Each applicable Transmission Owner and
recently-completed work. This requirement
applicable Generator Owner shall perform
sets a minimum Vegetation Inspection
a Vegetation Inspection of 100% of its
frequency of once per calendar year but
applicable transmission lines (measured in
with no more than 18 months between
units of choice - circuit, pole line, line
inspections on the same ROW. Based upon
miles or kilometers, etc.) at least once per
average growth rates across North America
calendar year and with no more than 18
and on common utility practice, this
calendar months between inspections on
minimum frequency is reasonable.
the same ROW 7 [Violation Risk Factor:
Transmission Owners should consider local
and environmental factors that could
7
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 23: September 29, 2011March 6, 2012
15
FAC-003-3 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 8
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
8
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 23: September 29, 2011March 6, 2012
16
FAC-003-3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
Draft 23: September 29, 2011March 6, 2012
17
FAC-003-3 — Transmission Vegetation Management
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
5.1.15.
Compliance Audit
5.1.16.
Self-Certification
5.1.17.
Spot Checking
5.1.18.
Compliance Violation Investigation
5.1.19.
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
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18
FAC-003-3 — Transmission Vegetation Management
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 23: September 29, 2011March 6, 2012
19
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
On November 3, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management with NERC staff-proposed changes to the VSLs for R1 and R2 in lieu of the Project 200707 SDT’s original proposed VSLs. The table below now reflects the VSLs for R1 and R2 that were
approved by NERC’s Board of Trustees. The only additional change made by the Project 2010-07 SDT
was to change “Transmission Owner” to “responsible entity.”
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 23: September 29, 2011March 6, 2012
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
20
A grow-in
The Transmission Owner failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
FAC-003-3 — Transmission Vegetation Management
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R3
Long-Term
Planning
Lower
R4
Real-time
Medium
R5
Operations
Planning
Medium
Draft 23: September 29, 2011March 6, 2012
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
21
FAC-003-3 — Transmission Vegetation Management
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
R6
R7
Operations
Planning
Operations
Planning
Medium
The responsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The responsible entity failed
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 23: September 29, 2011March 6, 2012
22
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC standards to cover the general effective
date and is sufficient to cover the vast majority of situations. Five special cases are needed to cover effective dates for individual lines
which undergo transitions after the general effective date. These special cases cover the effective dates for those lines which are
initially becoming subject to the standard, those lines which are changing their applicability within the standard, and those lines which
are changing in a manner that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to become elements of an IROL or Major
WECC Transfer Path in a future Planning Year (PY). For example, studies by the Planning Coordinator in 2011 may identify a line to
have that designation beginning in PY 2021, ten years after the planning study is performed. It is not intended for the Standard to be
immediately applicable to, or in effect for, that line until that future PY begins. The effective date provision for such lines ensures that
the line will become subject to the standard on January 1 of the PY specified with an allowance of at least 12 months for the
applicable Transmission Owner or applicable Generator Owner to make the necessary preparations to achieve compliance on that line.
The table below has some explanatory examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or Major WECC Transfer Path may be
removed from that designation due to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network.
Draft 23: September 29, 2011March 6, 2012
23
FAC-003-3 — Transmission Vegetation Management
Case 3 is needed because a line operating at 200 kV or above that once was designated as an element of an IROL or Major WECC
Transfer Path may be removed from that designation due to system improvements, changes in generation, changes in loads or changes
in studies and analysis of the network. Such changes result in the need to apply R1 to that line until that date is reached and then to
apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be acquired by an applicable Transmission
Owner or applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line
solely for local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is
incorporating the line into the interconnected electrical energy transmission network which will thereafter make the line subject to the
standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an applicable Transmission Owner or
applicable Generator Owner from a third party such as a Distribution Provider or other end-user who was using the line solely for
local distribution purposes, but the applicable Transmission Owner or applicable Generator Owner, upon acquisition, is incorporating
the line into the interconnected electrical energy transmission network. In this special case the line upon acquisition was designated as
an element of an Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set forth in Paragraph 734 of FERC
Order 693. The Order pointed out that Transmission Owners may in some cases own more property or rights than are needed to reliably
operate transmission lines. This modified definition represents a slight but significant departure from the strict legal definition of “right
of way” in that this definition is based on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow the use of such vegetation widths if
there were no engineering or construction standards that referenced the width of right of way to be maintained for vegetation on a
particular line but the evidence exists in maintenance records for a width that was in fact maintained prior to this standard becoming
mandatory. Such widths may be the only information available for lines that had limited or no vegetation easement rights and were
typically maintained primarily to ensure public safety. This standard does not require additional easement rights to be purchased to
satisfy a minimum right of way width that did not exist prior to this standard becoming mandatory.
Draft 23: September 29, 2011March 6, 2012
24
FAC-003-3 — Transmission Vegetation Management
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance inspections and vegetation inspections
to be performed concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation and/or slow
vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a method of calculating a flash over
distance that has been used in the design of high voltage transmission lines. Keeping vegetation away from high voltage conductors by
this distance will prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3 and associated Figure
1. Table 2 below provides MVCD values for various voltages and altitudes. Details of the equations and an example calculation are
provided in Appendix 1 of the Technical Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the management of vegetation
such that there are no vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the
same requirements; however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission Owner or
applicable Generator Owner to manage vegetation to prevent encroachment within the MVCD of transmission lines. R1 is applicable to
lines that are identified as an element of an IROL or Major WECC Transfer Path. R2 is applicable to all other lines that are not
elements of IROLs, and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation management for an applicable line that is
an element of an IROL or a Major WECC Transfer Path is a greater risk to the interconnected electric transmission system than
applicable lines that are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not elements of IROLs or
Major WECC Transfer Paths do require effective vegetation management, but these lines are comparatively less operationally
significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and
Medium for R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to encroach within the MVCD distance as
shown in Table 2, it is a violation of the standard. Table 2 distances are the minimum clearances that will prevent spark-over based on
the Gallet equations as described more fully in the Technical Reference document.
Draft 23: September 29, 2011March 6, 2012
25
FAC-003-3 — Transmission Vegetation Management
These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is
intentionally or inadvertently operated beyond its Rating and Rated Electrical Operating Condition (potentially in violation of other
standards), the occurrence of a clearance encroachment may occur solely due to that condition. For example, emergency actions taken
by an applicable Transmission Owner or applicable Generator Owner or Reliability Coordinator to protect an Interconnection may
cause excessive sagging and an outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a vegetation encroachment into the MVCD
(absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the
ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of the lines and vegetation
located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. Faults which do not
cause a Sustained outage and which are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the severity of a failure of an applicable
Transmission Owner or applicable Generator Owner to manage vegetation and to the corresponding performance level of the
Transmission Owner’s vegetation program’s ability to meet the objective of “preventing the risk of those vegetation related outages
that could lead to Cascading.” Thus violation severity increases with an applicable Transmission Owner’s or applicable Generator
Owner’s inability to meet this goal and its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will
promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to
the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example initial investigations and
corrective actions may not identify and remove the actual outage cause then another outage occurs after the line is re-energized and
previous high conductor temperatures return. Such events are considered to be a single vegetation-related Sustained Outage under the
standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating
voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission
outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines operated at nominal voltage levels not listed
in Table 2, then the applicable TO or applicable GO should use the next largest clearance distance based on the next highest nominal
voltage in the table to determine an acceptable distance.
Draft 23: September 29, 2011March 6, 2012
26
FAC-003-3 — Transmission Vegetation Management
Requirement R3: R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or
specifications, an applicable Transmission Owner or applicable Generator Owner uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the applicable Transmission Owner or
applicable Generator Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to
the transmission system. The approach provides the basis for evaluating the intent, allocation of appropriate resources, and the
competency of the applicable Transmission Owner or applicable Generator Owner in managing vegetation. There are many
acceptable approaches to manage vegetation and avoid Sustained Outages. However, the applicable Transmission Owner or
applicable Generator Owner must be able to show the documentation of its approach and how it conducts work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a
utility uses to manage vegetation, any approach an applicable Transmission Owner or applicable Generator Owner chooses to use will
generally contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to
ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a number of different loading variables.
Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal
loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind
velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by
combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is
illustrated in Figure 1 below. In the Technical Reference document more figures and explanations of conductor dynamics are
provided.
Draft 23: September 29, 2011March 6, 2012
27
FAC-003-3 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is shown with six possible conductor
positions due to movement resulting from thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially
threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific
transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular
service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of an applicable
Transmission Owner or applicable Generator Owner employee who personally identifies such a threat in the field. Confirmation
could also be made by sending out an employee to evaluate a situation reported by a landowner.
Draft 23: September 29, 2011March 6, 2012
28
FAC-003-3 — Transmission Vegetation Management
Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue)
or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include
an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to ensure the proper communication
between field personnel and the control center to allow the control center to take the appropriate action until or as the vegetation threat
is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or other
preparatory actions in recognition of the increased risk of outage on that circuit. The notification of the threat should be
communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some
applicable Transmission Owners or applicable Generator Owners may have a danger tree identification program that identifies trees
for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an
immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the applicable Transmission Owner or applicable
Generator Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance.
The intent of this requirement is to deal with situations that prevent the applicable Transmission Owner or applicable Generator
Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk.
Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the
discovery of easement stipulations which limit the applicable Transmission Owner’s or applicable Generator Owner’s rights, or other
circumstances.
This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be
rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals
on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the applicable Transmission
Owner or applicable Generator Owner is not under any immediate time constraint for achieving the management objective, can easily
reschedule work using an alternate approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint, the applicable Transmission Owner
or applicable Generator Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A
wide range of actions can be taken to address various situations. General considerations include:
Draft 23: September 29, 2011March 6, 2012
29
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable Generator Owner is constrained from
performing planned vegetation maintenance work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance
work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line the applicable Transmission Owner
or applicable Generator Owner could consider location specific measures such as modifying the inspection and/or
maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could
include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document and track the specific corrective
action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one
property where the constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections. The provision
that Vegetation Inspections can be performed in conjunction with general line inspections facilitates a Transmission Owner’s ability to
meet this requirement. However, the applicable Transmission Owner or applicable Generator Owner may determine that more
frequent vegetation specific inspections are needed to maintain reliability levels, based on factors such as anticipated growth rates of
the local vegetation, length of the local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the applicable lines to be inspected. To
calculate the appropriate VSL the applicable Transmission Owner or applicable Generator Owner may choose units such as: circuit,
pole line, line miles or kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates 2,000 miles of applicable transmission
lines this applicable Transmission Owner or applicable Generator Owner will be responsible for inspecting all the 2,000 miles of lines
at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then
the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 23: September 29, 2011March 6, 2012
30
FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator Owner is required to complete its an
annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to
changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the
transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a
“line-by-line” detailed description of all work to be performed. It is only intended to require that the applicable Transmission Owner
or applicable Generator Owner provide evidence of annual planning and execution of a vegetation management maintenance approach
which successfully prevents encroachment of vegetation into the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies 1,000 miles of applicable
transmission lines to be completed in the applicable Transmission Owner’s or applicable Generator Owner’s annual plan, the
applicable Transmission Owner or applicable Generator Owner will be responsible completing those identified miles. If a applicable
Transmission Owner or applicable Generator Owner makes a modification to the annual plan that does not put the transmission system
at risk of an encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until next year the calculation
to determine what percentage was completed for the current year would be: 1000 – 100 (deferred miles) = 900 modified annual plan,
or 900 / 900 = 100% completed annual miles. If an applicable Transmission Owner or applicable Generator Owner only completed
875 of the total 1000 miles with no acceptable documentation for modification of the annual plan the calculation for failure to
complete the annual plan would be: 1000 – 875 = 125 miles failed to complete then, 125 miles (not completed) / 1000 total annual
plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable Generator Owner to change priorities or
treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify
unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a
major storm could require redirecting local resources away from planned maintenance. This situation may also include complying
with mutual assistance agreements by moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan
provided that they do not put the transmission system at risk of a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the applicable Transmission Owner’s or
applicable Generator Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full
extent of legal rights on the ROW is superior to incremental management because in the long term it reduces the overall potential for
encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient.
Draft 23: September 29, 2011March 6, 2012
31
FAC-003-3 — Transmission Vegetation Management
When developing the annual work plan the applicable Transmission Owner or applicable Generator Owner should allow time for
procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for
obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Applicable Transmission Owners
or applicable Generator Owners may also need to consider those special landowner requirements as documented in easement
instruments.
This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore,
deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by
the applicable Transmission Owner or applicable Generator Owner, evidence of successful annual work plan execution could consist
of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed
work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.
Draft 23: September 29, 2011March 6, 2012
32
FAC-003-3 — Transmission Vegetation Management
Draft 23: September 29, 2011March 6, 2012
33
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 9
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
69*
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
9
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 23: September 29, 2011March 6, 2012
34
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
69*
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 23: September 29, 2011March 6, 2012
35
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists
who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more
appropriate is explained in the paragraphs below.
Draft 23: September 29, 2011March 6, 2012
36
FAC-003-3 — Transmission Vegetation Management
The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic
maximum transient over-voltages factors for in-service transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-516-2003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines
with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the
minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were
developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in
IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions.
Consequently, the validity of using these distances in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 7
could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 5 would
have to be used. Table 5 represented minimum air insulation distances under the worst possible case for transient over-voltage factors.
These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV
phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this
particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the
line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from
becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case
transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that
occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are
negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere
along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient overvoltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g.
closing resistors). At voltage levels where capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the
Draft 23: September 29, 2011March 6, 2012
37
FAC-003-3 — Transmission Vegetation Management
maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank
switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order
to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient
over-voltage factor of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic maximum in this
application. Likewise, for ac transmission lines operated at Maximum System Voltages of 362 kV and above a transient over-voltage
factor of 1.4 per unit is considered a realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the
required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications
and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap
geometries. This approach was used to design the first 500 kV and 765 kV lines in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances
computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the
Gallet equations yield a more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same
transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516
equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the
Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas
currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been
used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor
that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations.
Draft 23: September 29, 2011March 6, 2012
38
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 23: September 29, 2011March 6, 2012
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
39
Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired at midnight the day before FAC-003-X becomes effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
1
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMP and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees adoption.
3
Implementation Plan for FAC-003-3 —
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC glossary upon approval of FAC-003-3, or the above definition of
Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at midnight the
day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has been
approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on order in which regulatory authorities approved FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming (as is required by
FAC-003-3 Requirement 1.3). Once a complete inventory is created, the Generator Owner will begin
the process of gathering information for the TVMP. In instances where the generation interconnection
Facilities are owned by a partnership, a majority or operating partner will need to obtain partnership
approval to proceed with procurement of a TVMP expert, and later a tree trimming crew. Typically, a
Implementation Plan for FAC-003-3
2
request for proposal to hire TVMP consultant is initiated which could take several weeks in order to
obtain sufficient bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received,
a contract with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator Owner
staff and the TVMP consultant will need to perform a Right-of-Way inspection (as required in FAC-0033 Requirement 1), usually done using GPS, LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-003-3
Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation (as required in FAC-003-3
Requirement 1.2). On an ongoing basis, in addition to performing inspections and clearances as
required by the entity's TVMP, the Generator Owner will need to ensure that the training and
qualification requirements for the standard are met. The entity will also need to maintain
documentation of all FAC-003-3 activities for compliance period of one year to meet compliance with
the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
Implementation Plan for FAC-003-3
3
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees adoption.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
4
Unofficial Comment Form
Generator Requirements at the Transmission Interface (Project 2010-07)
Please DO NOT use this form to submit comments. Please use the electronic comment form to submit
comments on the first formal posting for Project 2010-07—Generator Requirements at the
Transmission Interface. The electronic comment form must be completed by April 09, 2012.
2010-07 Project Page
If you have questions please contact Mallory Huggins at mallory.huggins@nerc.net or 202-644-8062.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Elements and Facilities that are considered by some entities to be Transmission, these are
most often radial Facilities that are not part of the integrated grid, and as such should not be subject to
the same standards applicable to Transmission Owners and Transmission Operators who own and
operate Transmission Elements and Facilities that are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. However, registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators.
On January 20, 2012, Exelon submitted a Level One Appeal of the standard process for FAC-003-3 and
FAC-003-X to NERC’s Vice President of Standards and Training that stated the following: “Exelon
believes that the NERC Standards Process Manual was not followed, and that based on the substantive
changes made to both Standards following the Initial Ballot, NERC should have set the Standards for
vote using a Successive Ballot rather than a Recirculation Ballot.”
NERC’s Vice President of Standards and Training submitted a timely response to the appeal that found
that “Exelon…made its case that the [Standard Processes Manual] was not adhered to and that a
change impacting applicability was made between the last successive and recirculation ballot.”
Accordingly, the Vice President of Standards and Training referred the issue to the Standards
Committee for handling, suggesting the following options:
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
1
1. Re-post the standard for a successive ballot and recirculation ballot. Essentially set the clock
back and correctly replay the last steps of the process.
2. Ask the SDT to remove the clarification language from the final standard and go directly to
recirculation ballot.
3. Ask the SDT to redesign the challenged portion of the proposed standard.
He recommended that the Standards Committee pursue option 2. In a Standards Committee Executive
Committee (SCEC) conference call on February 23, 2012, the SCEC directed NERC staff to void the FAC003-3 and FAC-003-X recirculation ballot results of December 2011 and “remand the work to the
drafting team with direction to take into account the issues raised in the Exelon appeal submitted in
response to the recirculation ballot previously conducted and either: modify the language added
following the initial ballot and then re-post the standard for a successive ballot, or remove the
language added following the initial ballot and go directly to recirculation ballot.”
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments
submitted in the first successive ballot between October 5 and November 18, 2011. The SDT continues
to believe that a reference to line of sight is clarifying and makes explicit the SDT’s implicit intent from
day one. Thus, it kept the line of sight reference but made a few additional changes for formatting
clarity and language consistency. The team also added a footnote to further explain what it means by
“line of sight.”
Additionally, “Regional Entity” was removed from the Applicability section of FAC-003-X because it is
not a Functional Entity according to the Functional Model.
The FAC-003-3 and FAC-003-X recirculation ballot results of December 2011 have been voided, and
both standards are being posted for a 30-day concurrent comment period and successive ballot to
allow stakeholders the opportunity to comment on these changes.
The appeal and NERC response are posted on the 2010-07 project page.
Status of other standards that are part of Project 2010-07:
•
•
FAC-001-1 and PRC-004-2.1a were adopted by NERC’s Board of Trustees on February 9, 2012
PRC-005-1.1a is currently posted for a 45-day concurrent comment and initial ballot.
No standards modified under Project 2010-07 will be filed with regulatory authorities until the Board of
Trustees has acted on the complete package of four standards.
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
2
You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments
submitted in the first successive ballot between October 5 and November 18, 2011, along with
advice from NERC staff. The SDT continues to believe that a reference to line of sight is clarifying
and makes explicit the SDT’s implicit intent from day one. Thus, it kept the line of sight reference
but made a few additional changes for formatting clarity and language consistency. The team also
added a footnote to further explain what it means by “line of sight.” Do you agree with these
changes? If not, please provide specific alternative language.
Yes
No
Comments:
Unofficial Comment Form
Generator Requirements at the Transmission Interface (2010-07)
3
Approved Meeting Minutes
Standards Committee Executive Committee
February 23, 2012 | 1:00 p.m. Eastern
1. Administrative Items
a . Introductions and Quorum
Allen Mosher welcomed all and verified there was a quorum with four of the five Standards
Committee Executive Committee members present.
Standards Committee Executive Committee members attending:
•
•
•
•
John Bussman, Associated Electric Cooperative Inc.
David Kiguel, Hydro One Networks Inc.
Allen Mosher, American Public Power Association
Jason Shaver, American Transmission Company
Additional Standards Committee members in attendance:
• Michael Gildea, Dominion Resources Services, Inc.
• Scott Miller, MEAG Power
• Fled Plett, MA Attorney General
• Joseph Tarantino, SMUD
Also attending:
• James Case, Entergy
• Juan Diaz, Customized Energy Solutions
• Andrew Dressel, NERC
• José H. Escamilla, CPS Energy
• Laura Lee, Duke Energy
• Maureen Long, NERC
• Jason Marshall, ACEs Power
• Steven Naumann, Exelon Corporation
• Jerry Parnell, City Water, Light & Power
• Robert Rhodes, SPP
• Andy Rodriquez, NERC
• Herbert Schrayshuen, NERC
• Louis Slade, Dominion Resources
• David Taylor, NERC
• Rick Terrill, Luminant Power
a . Conference Call Reminder and Antitrust Guidelines
Maureen Long reminded all that the conference call was open to all interested parties and
reviewed the NERC Antitrust Compliance Guidelines.
2. Level 1 Appeal of FAC-003-3 and FAC-003x in Project 2010-07
Between the initial and recirculation ballots, the drafting team working on Project 2010-07 – Generator
Requirements at the Transmission Interface made an identical modification to two standards (FAC-0033 and FAC-003-x). While the drafting team felt that the modification was not significant, Exelon did
consider the modification as “significant” and filed an appeal. Herbert Schrayshuen reviewed available
evidence from the appellant, the drafting team, and the standards staff and concluded that the change
made to the standards did change the scope of applicability and the standards should have been
posted for successive rather than recirculation ballots. The chair of the SC, Allen Mosher came to the
same conclusion.
After discussion of available options, John Bussman motioned to direct the standards staff to void
the recirculation ballot results for FAC-003-3 and FAC-003-x and remand the work to the SDT with
direction to take into account the issues raised in the Exelon appeal and either:
• Modify the language added following the initial ballot and then post the standard for a
successive ballot, or
•
Remove the language added following the initial ballot and go directly to recirculation
ballot.
− The motion was approved without objection or abstention.
3. Adjourn
SCEC and QRAWG February 23, 2012 Meeting Minutes
2
Allen Mosher
Standards Committee Chair
March 6, 2012
Louis Slade
Dominion Resources
120 Tredegar St.
Richmond, VA 23219
Dear Louis,
The purpose of this letter is to advise the members of the Generator Requirements at the Transmission
Interface Standard Drafting Team of the results of a Level 1 Appeal of the recirculation ballots
conducted for FAC-003-3 and FAC-003-x. The Appeal was filed on behalf of Exelon Corporation, alleging
that the drafting team made a substantive change to both FAC-003-3 and FAC-003-x between the
initial and the recirculation ballots.
In accordance with the Standard Processes Manual, the appeal was submitted to Herbert Schrayshuen,
NERC’s Vice President of Standards and Training. Mr. Schrayshuen reviewed available evidence from
the appellant, the drafting team, and the standards staff and concluded that the change made to the
standards prior to the recirculation ballot did change the scope of applicability and he ruled that the
standards should have been posted for successive rather than recirculation ballots.
On February 23, 2012 the Standards Committee’s Executive Committee (SCEC) reviewed the results of
Mr. Schrayshuen’s findings and agreed with Mr. Schrayshuen’s conclusions. As a result, the SCEC
directed the standards staff to void the results of the recirculation ballots for FAC-003-3 and FAC-003-x
and, through this letter, is remanding FAC-003-3 and FAC-003-x to the Project 2010-07 – Generator
Requirements at the Transmission Interface Standard Drafting Team. The SCEC directs the drafting
team to take into account the issues raised in the Exelon appeal and either:
•
Modify the language added following the initial ballot and then post the standard for a
successive ballot, or
•
Remove the language added following the initial ballot and go directly to recirculation ballot.
Thank you in advance for your prompt attention to these issues and for the GO-TO Standard Drafting
Team’s commitment of time and energy to reliable operations and the resolution of stakeholder
concerns through the NERC standards process. Please do not hesitate to contact me or NERC standards
staff should you have any questions.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Sincerely,
Allen Mosher
Standards Committee Chair
cc: Herbert Schrayshuen
Steven T. Naumann
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
The SDT’s technical justification
document has not changed
substantively since it was posted in
December 2011, but the document
below has been updated to reflect
the posted changes to FAC-003-3 and
FAC-003-X.
As part of its work on Project 2010-07—Generator
Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability
standards and 102 requirements to determine what
changes are necessary to close a reliability gap with
respect to what is commonly known as the generator
interconnection Facility. Many of these standards and requirements had been addressed in the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad Hoc
Report) and additional standards were reviewed as a result of informal discussions with NERC and FERC
staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004 and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new,
glossary terms.
Project 2010-07 Technical Justification Document
2
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT agrees
with that intended exclusion in principle; as it discusses in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT recognizes that in
many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2)
the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for
exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Project 2010-07 Technical Justification Document
3
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, to clarify the exemption,
the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station switchyard to the
point of interconnection with a Transmission Owner’s Facility or (2) does not have a clear line of
sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s Facility and are:
Operated at 200kV or higher; or operated below 200kV identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
The SDT took into consideration all comments submitted in both formal comment periods, and
believes that this exemption now adequately addresses the reliability impact for a majority of the
Facilities, while balancing the efforts necessary to support the standard from all entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
Project 2010-07 Technical Justification Document
4
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
PER-001-0
Ad Hoc Report*
X
X
NERC Directive
FERC Order
X
X
X
X
X
X
X
X
Project 2010-07 Technical Justification Document
5
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
Project 2010-07 Technical Justification Document
6
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Project 2010-07 Technical Justification Document
7
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
Project 2010-07 Technical Justification Document
8
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
Project 2010-07 Technical Justification Document
9
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
Project 2010-07 Technical Justification Document
10
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
Project 2010-07 Technical Justification Document
11
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a localarea view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Project 2010-07 Technical Justification Document
12
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
Project 2010-07 Technical Justification Document
13
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
Project 2010-07 Technical Justification Document
14
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Project 2010-07 Technical Justification Document
15
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
16
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
The SDT’s technical justification
document has not changed
substantively since it was posted in
December 2011, but the document
below has been updated to reflect
the posted changes to FAC-003-3 and
FAC-003-X.
As part of its work on Project 2010-07—Generator
Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability
standards and 102 requirements to determine what
changes are necessary to close a reliability gap with
respect to what is commonly known as the generator
interconnection Facility. Many of these standards and requirements had been addressed in the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad Hoc
Report) and additional standards were reviewed as a result of informal discussions with NERC and FERC
staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004 and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new,
glossary terms.
Project 2010-07 Technical Justification Document
2
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT agrees
with that intended exclusion in principle; as it discusses in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT recognizes that in
many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2)
the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for
exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Project 2010-07 Technical Justification Document
3
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, to clarify the exemption,
the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station switchyard to the
point of interconnection with a Transmission Owner’s Facility or (2) does not have a clear line of
sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s Facility and are:
Operated at 200kV or higher; or operated below 200kV identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
sections 4.3.1 of both versions of FAC-003 (which address applicable generation Facilities) now state:
“Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond the fenced
area of the generating switchyard or do not have a clear line of sight from the switchyard fence to the
point of interconnection and are…”
The SDT took into consideration all comments submitted in both formal comment periods, and
believes that this exemption now adequately addresses the reliability impact for a majority of the
Facilities, while balancing the efforts necessary to support the standard from all entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
Project 2010-07 Technical Justification Document
4
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
Ad Hoc Report*
X
X
Project 2010-07 Technical Justification Document
NERC Directive
FERC Order
X
X
X
X
5
FAC-014-2
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
Project 2010-07 Technical Justification Document
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“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Project 2010-07 Technical Justification Document
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Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
Project 2010-07 Technical Justification Document
8
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
Project 2010-07 Technical Justification Document
9
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
Project 2010-07 Technical Justification Document
10
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
Project 2010-07 Technical Justification Document
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The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a local-
Project 2010-07 Technical Justification Document
12
area view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Project 2010-07 Technical Justification Document
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Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
Project 2010-07 Technical Justification Document
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The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Project 2010-07 Technical Justification Document
15
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
16
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07
On January 20, 2012, Exelon submitted a Level One Appeal of the standard process for FAC-003-3 and
FAC-003-X to NERC’s Vice President of Standards and Training that stated the following: “Exelon
believes that the NERC Standards Process Manual was not followed, and that based on the substantive
changes made to both Standards following the Initial Ballot, NERC should have set the Standards for
vote using a Successive Ballot rather than a Recirculation Ballot.”
NERC’s Vice President of Standards and Training submitted a timely response to the appeal that found
that “Exelon…made its case that the [Standard Processes Manual] was not adhered to and that a
change impacting applicability was made between the last successive and recirculation ballot.”
Accordingly, the Vice President of Standards and Training referred the issue to the Standards
Committee for handling, suggesting the following options:
1. Re-post the standard for a successive ballot and recirculation ballot. Essentially set the clock
back and correctly replay the last steps of the process.
2. Ask the SDT to remove the clarification language from the final standard and go directly to
recirculation ballot.
3. Ask the SDT to redesign the challenged portion of the proposed standard.
He recommended that the Standards Committee pursue option 2. In a Standards Committee Executive
Committee (SCEC) conference call on February 23, 2012, the SCEC directed NERC staff to void the FAC003-3 and FAC-003-X recirculation ballot results of December 2011 and “remand the work to the
drafting team with direction to take into account the issues raised in the Exelon appeal submitted in
response to the recirculation ballot previously conducted and either: modify the language added
following the initial ballot and then re-post the standard for a successive ballot, or remove the language
added following the initial ballot and go directly to recirculation ballot.”
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments
submitted in the first successive ballot between October 5 and November 18, 2011. The SDT continues
to believe that a reference to line of sight is clarifying.
With this line of sight reference, the SDT simply seeks to clarify the exception language based on the
intent that has been agreed upon by the stakeholder body. In its Consideration of Comments report
from the last formal comment period, which ended on July 17, 2011, the SDT explained “We believe
that the one mile length is a reasonable approximation of line of sight, and that using a fixed starting
point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion
on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference
here, the SDT believes it has clarified its original intent and appropriately considered all comments
submitted.
The SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station switchyard to the
point of interconnection with a Transmission Owner’s Facility or (2) does not have a clear line of
sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s Facility and are:
Operated at 200kV or higher; or operated below 200kV identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
Additionally, “Regional Entity” has been removed from the applicability section of FAC-003-X because it
is not a recognized Functional Entity.
The FAC-003-3 and FAC-003-X recirculation ballot results of December 2011 have been voided, and
both standards are being posted for a 30-day concurrent comment period and successive ballot to
allow stakeholders the opportunity to comment on these changes.
Members of the ballot pool should note that for this ballot, the SDT will be balloting both FAC-003-3
and FAC-003-X, but stakeholders should not vote as though they are choosing one or the other. The
SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X
ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
2
other words, stakeholders who support adding GOs to the applicability of FAC-003 should vote in the
affirmative for both FAC-003-3 and FAC-003-X.
The Exelon appeal and NERC response are posted on the 2010-07 project page.
Status of other standards that are part of Project 2010-07:
•
•
FAC-001-1 and PRC-004-2.1a were adopted by NERC’s Board of Trustees on February 9, 2012
PRC-005-1.1a is currently posted for a 45-day concurrent comment and initial ballot.
No standards modified under Project 2010-07 will be filed with regulatory authorities until the Board of
Trustees has acted on the complete package of four standards.
While this summary has been updated to reflect the status of FAC-003-3 and FAC-003-X, the SDT’s
responses to stakeholder comments below have not changed, except as they relate to FAC-003-3 and
FAC-003-X.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.) …. .............................................................. 12
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1? …. ........................................................................................... 29
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some
commenters found the half-mile length too short, others found it too long, and still others found
the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its
latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile
beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the
part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this
qualifier for Generator Owners because there is a very low risk from vegetation within the line of
sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a
decision that will be made as Project 2007-07—Vegetation Management moves forward, do you
support the proposed redline changes to FAC-003-X and FAC-003-3? …. ....................................... 34
4.
Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X? …. ......................................................................................... 50
5.
In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here. …. ...................................................................................... 57
6.
In its technical justification document, the SDT reviews all standards that had been proposed for
substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for any
of these decisions, please include suggested language here. …. ..................................................... 63
7.
The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
4
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the set
of standards currently posted achieve this goal? …. ......................................................................... 74
8.
If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the
appropriate ones? ….......................................................................................................................... 87
9.
If you answered “no” to Question 7, what standards need to be added or removed to achieve the
SDT’s goal? Please provide technical justification for your answer. …. ............................................ 91
10. Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 99
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
5
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Gerald Beckerle
SERC OC Standards Review Group
1.
Scott Brame
NCEMC
2.
Troy Willis
Georgia Transmission Corp. SERC 1
3.
Mike Hirst
Cogentrix
SERC 5
4.
Bob Dalrymple
TVA
SERC 1, 3, 5, 6
5.
Matt Carden
Southern Co.
SERC 1, 5
6.
Shardra Scott
Gulf Power Co.
SERC 3
7.
Kerry Sibley
Georgia Transmission Corp. SERC 1
8.
Andy Burch
EEI
SERC 5
9.
Shaun Anders
City of Springfield (CWLP)
SERC 1, 3
SERC 1, 3, 5
11. John Troha
SERC 10
2.
Group
Jonathan Hayes
X
Southwest Power Pool Standards
Development Team
Additional Member Additional Organization Region Segment Selection
3
X
SERC 1, 3, 4, 5
10. Melinda Montgomery Entergy
SERC Reliability Corp
2
X
4
5
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Jonathan Hayes
Southwest Power Pool
SPP
2
2.
Robert Rhodes
Southwest Power Pool
SPP
2
3.
Don Taylor
Westar
SPP
1, 3, 5, 6
4.
John Allen
City Utilities of Springfield
SPP
1, 4
5.
Sean Simpson
MCPBPU
SPP
1, 3, 5
6.
Louis Guidry
CLECO
SPP
1, 3, 5
7.
Mitch Williams
Western Farmers
SPP
1, 3, 5
8.
Valerie Pinnamonti
AEP
SPP
1, 3, 5
9.
Bud Averill
Grand River Dam Authority SPP
1, 3, 5
OGE
1, 3, 5
10. Terri Pyle
3.
Group
SPP
Guy Zito, Guy Zito
Additional Member
2
3
4
5
6
7
Northeast Power Coordinating Council,
Northeast Power Coordinating Council
Additional Organization
Region
Alan Adamson
New York State Reliability Council, LLC
NPCC, NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC, NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC, NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC, NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC, NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC, NPCC 2
9.
Chantel Haswell
NPCC, NPCC 10
FPL Group, Inc.
NPCC, NPCC 5
10. David Kiguel
Hydro One Networks Inc.
NPCC, NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC, NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC, NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC, NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC, NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC, NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC, NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC, NPCC 5
18. Saurabh Saksena
National Grid
NPCC, NPCC 1
19. Michael Schiavone
National Grid
NPCC, NPCC 1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
10
X
Segment Selection
1.
8
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
20. Wayne Sipperly
New York Power Authority
NPCC, NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC, NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC, NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC, NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 3
4.
Group
Emily Pennel
No additional members listed.
Southwest Power Pool Regional Entity
5.
MRO NSRF
Group
Will SMith
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Jodi Jenson
WAPA
MRO
1, 6
4.
Ken Goldsmith
ALTW
MRO
4
5.
Alice Ireland
XCEL/NSP
MRO
1, 3, 5, 6
6.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
7.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
8.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
9.
Scott Nickels
RPU
MRO
4
10. Terry Harbour
MEC
MRO
1, 3, 5, 6
11. Marie Knox
MISO
MRO
2
12. Lee Kittelson
OTP
MRO
1, 3, 4, 5
13. Scott Bos
MPW
MRO
1, 3, 5, 6
14. Tony Eddleman
NPPD
MRO
1, 3, 5
15. Mike Brytowski
GRE
MRO
1, 3, 5, 6
16. Richard Burt
MPC
MRO
1, 3, 5, 6
6.
Group
Charles W. Long
Additional Member
Additional Organization
SERC Planning Standards Subcommittee
X
X
Region Segment Selection
1. Pat Huntley
SERC
SERC
10
2. John Sullivan
Ameren Services Co.
SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Bob Jones
Southern Company Services SERC
1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Jason Adams
7.
TVA
Group
SERC
Frank Gaffney
2
3
4
5
6
7
1
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
8.
Group
FRCC
Mike Garton
Additional Member
Dominion
Additional Organization
Region Segment Selection
1. Michael Gildea
Dominion Resources Services, Inc.
RFC
2. Connie Lowe
Dominion Resources Services, Inc.
NPCC 5, 6
3. Michael Crowley
Virginia Electric and Power Company RFC
9.
Group
Annette M. Bannon
Additional Member
Additional Organization
5, 6
1, 3
PPL NERC Registered Affiliates
Region Segment Selection
1. Brent Ingebrigston
LG&E and KU Services Co.
SERC
3
2. Don Lock
PPL Brunner Island, LLC
RFC
5
3.
PPL Martins Creek, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Montour, LLC
RFC
5
6.
Lower Mount Bethel Energy, LLC RFC
5
7. Annete Bannon
PPL Susquehanna, LLC
5
8. Leland McMillan
PPL Montana, LLC
10.
Group
Jason Marshall
Additional Member
Additional Organization
RFC
WECC 5
ACES Power Marketing Standards
Collaborators
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power
RFC
2. Erin Woods
East Kentucky Power Cooperative SERC
1, 3, 5, 6
3. Michael Brytowski
Great River Energy
1, 3, 5, 6
MRO
3, 5, 6
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11.
2
3
4
5
6
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
12.
Jack Cashin
Electric Power Supply Association
X
X
Individual
14. Individual
Natalie McIntire
Tom Flynn
American Wind Energy Association
Puget Sound Energy, Inc.
X
X
X
15.
Individual
Silvia Parada Mitchell
Compliance & Responsbility Organization
16.
Individual
Southern Company
Individual
Antonio Grayson
Chris Higgins/Stephen
Enyeart/Chuck
Mathews/Charles
Sheppard
18.
Individual
Thad Ness
American Electric Power
19.
Individual
BP Wind Energy North America Inc.
Individual
Carla Bayer
John Bee on behalf of
Exelon
Individual
Dennis Sismaet
Individual
Michelle D'Antuono
Seattle City Light
Ingleside Cogeneration LP (Occidental
Chemical)
23.
Individual
Michael Falvo
Independent Electricity System Operator
24.
Individual
Greg Rowland
Duke Energy
X
25.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
26.
Individual
Kirit Shah
Ameren
27.
Individual
John Seelke
Individual
29. Individual
30.
31.
Individual
13.
17.
20.
21.
22.
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Bonneville Power Administration
X
X
X
Exelon
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PSEG
X
X
X
X
Andrew Z. Pusztai
RoLynda Shumpert
American Transmission Company
South Carolina Electric and Gas
X
X
X
X
Individual
Ravi Bantu
RES Americas Development
Individual
Katy Wilson
Sempra Generation
28.
7
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Joe Petaski
Manitoba Hydro
X
X
X
X
Individual
34. Individual
Chris de Graffenried
Ed Davis
Consolidated Edison Co. of NY, Inc.
Entergy Services
X
X
X
X
X
X
X
X
35.
Individual
Alice Ireland
Xcel Energy
X
Individual
Russell A. Noble
Cowlitz County PUD
X
X
X
36.
X
X
37.
Individual
Anthony Jablonski
ReliabiltiyFirst
X
38.
Individual
Donald Jones
Texas Reliability Entity
X
39.
Individual
Amir Hammad
Constellation Power Source Generation
40.
Individual
Dennis Chastain
Tennessee Valley Authority
32.
Individual
33.
X
X
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
X
11
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and removed the Generator Owner
from R4. Do you support the proposed redline changes to FAC-001-1? (Please refer to the posted FAC-001-1 technical
justification document for more information about the SDT’s rationale for its changes.)
Summary Consideration:
The SDT thanks all stakeholders for their comments and their 87% approval for the FAC-001-1 changes posted for ballot
in November 2011. Based on stakeholder feedback, the SDT has made the following minor changes to FAC-001-1:
-Corrected a typo in Applicability section 4.2.1 to change “within” to “with.”
-Corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather than just 3.1.1
through 3.1.6.
-Changed references to “Transmission System” to “interconnected Transmission systems” to ensure consistency with the
language elsewhere in the standard and in FAC-002-1.
Some stakeholders remain concerned about the intent of the SDT’s work on FAC-001-1. The SDT reminded them that the
scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with ownership or
operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should first address
“low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”) – that
is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
Through its deliberations, the SDT concluded that an interconnection Facility owned or operated by a GO or GOP that is
more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
Concerned commenters were also referred to one of the SDT’s resource documents: Project 2010-07: Generator
Requirements at the Transmission Interface Background Resource Document.
Some commenters suggested changes to Requirements R1 or R4, which deal exclusively with the Transmission Operator
and are outside the scope of the SDT’s work.
One commenter suggested formatting changes. The SDT agrees with the commenter that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the
standard and no change was made.
One commenter suggested that the phrase “Generator Owner’s existing Facility” be changed to “Generator Owner’s
existing Transmission Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part because in
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
12
some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC.
Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain the
term “Transmission.”
One commenter did not agree with the overall clarifying change to the Applicability section, but the SDT reminded this
commenter that this change was made to address previous comments that indicated that there was uncertainty as to
whether “another Facility to its existing generation Facility” was meant to address connecting additional generators by
the same GO. The SDT intends FAC-001-1 to apply only when the GO of an existing Facility executes an agreement to
evaluate the reliability impact of connecting additional generation owned by another GO. No change made with respect
to this comment.
A few stakeholders were concerned with the 45-day time frame included in the standard. The SDT pointed out that
majority of stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would
simply need to adopt (document and publish) the Facility connection requirements of its TO. No change to that time
frame was made.
Organization
Yes or No
Question 1 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While
the Technical Justification document states that the SDT intended to focus
on a Generator Owner’s radial interconnection facilities, the scope of the
revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
13
Organization
Yes or No
Question 1 Comment
transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis would most likely be
outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Southern Company
No
1) R4 is duplicative of R1 - either remove "maintain" from R1 or delete R4 both instances of "maintain" are not needed.  2) The measures, as
written, provide no additional indication of the evidence that could be
presented to demonstrate compliance with the Reliability Standard
Requirements. They provide little guidance on assessing non-compliance
with the Requirements.  
Response: Thank you for your comment. We agree with your suggestions, but both are outside the scope of this SDT. These items
will be submitted to the Issues Database to be addressed in a future revision of FAC-001.
Southwest Power Pool Standards
Development Team
No
Based on the applicability section of FAC-001 we feel that the strike through
should have been kept. It limited the requirement to just those generator
owners who had agreements in place, which we feel is appropriate.
Response: Thank you for your comment. This change was made to address previous comments that indicated to the SDT there was
uncertainty as to whether this was meant to address connecting additional generators by the same GO. The SDT intends FAC-001
to apply only when the GO of an existing Facility executes an agreement to evaluate the reliability impact of connecting additional
generation owned by another GO. No change made with respect to this comment.
Texas Reliability Entity
No
In Section 5.1, the reference to Regional Entity should be removed. There
are no requirements that apply to the Regional Entity.
In Requirements R1 and R4, “Planning Coordinator” should be added after
“Regional Entity.” In the ERCOT Region it is the Planning Coordinator that
maintains planning criteria and connection requirements. There is no NERC
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
14
Organization
Yes or No
Question 1 Comment
requirement or any obligation (as indicated in the technical justification
document) on the part of a GO to specifically execute an Agreement to
evaluate the reliability impact of interconnecting a third party Facility.
Therefore, this requirement’s applicability is contingent on a prerequisite
that may not occur, and that is under the control of the GO. This
assumption on the part of the SDT unnecessarily complicates the
compliance monitoring and enforcement of this standard. For instance, if
an “Agreement” is not executed, a GO is not required to comply with the
requirement, even though the GO may ultimately interconnect with another
entity. The requirement should be modified to include an applicability
trigger similar to that of FAC-002-1, so that once a GO “seek[s] to integrate .
. .,” i.e., agrees to or is compelled to allow a third-party interconnection,
then the requirement becomes applicable. Otherwise, the compliance and
monitoring is subject to the SDT’s speculation as indicated in this language
included in the technical justification document: “However, the SDT cannot
be certain this is the only example and it therefore proposes to add this new
requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a
third party to interconnect, have the necessary expertise to conduct the
required interconnect studies to meet this standard. Assuming that a
regulatory body would require a Generator Owner to evaluate such an
interconnection request, the SDT expects the Generator Owner and the
third party to execute some form of an Agreement.”
Response: Thank you for your comment. All of these comments are outside the scope of the SAR and the SDT’s work because they
refer specifically to the sections and requirements that apply to the TO alone. We encourage you to consider submitting a SAR that
addresses your concerns.
Manitoba Hydro
No
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
15
Organization
Yes or No
Question 1 Comment
While the Technical Justification document states that the SDT intended to
focus on a Generator Owner’s radial interconnection facilities, the scope of
the revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
2) If the drafting team intends to limit the scope of FAC-001-1 to GO owned
radial generator interconnection facilities that are not deemed BES
transmission and therefore would not require the registration of the GO as
a TO, Manitoba Hydro disagrees with the proposed changes to FAC-001-1 as
Generator Owners may not have the models or expertise to perform
interconnection studies to determine if there is an impact on the
Transmission Network. This concern is echoed in the technical justification
document provided by NERC: ‘the SDT acknowledges that the Generator
Owner may not, at the time it agrees or is compelled to allow a third part to
interconnect, have the necessary expertise to conduct the required
interconnect studies to meet this standard... the Generator Owner will have
to acquire such expertise. How the Generator Owner chooses to do so is
not for the SDT to determine.’ Although it may not be for the SDT to
determine how a GO obtains technical expertise, ensuring that such
expertise is acquired before a GO conducts the required interconnection
studies should be a concern to NERC as this directly affects the reliability of
the BES. As a result, all interconnection requests should be implemented by
the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User
facility as the TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If the scope
of FAC-001-1 also applies to GO owned BES transmission facilities, Manitoba
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
Hydro strongly believes that the Compliance Registry should apply and the
GOs should be required to register as a TO and abide by all applicable
standards to that functional type. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected
TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is
maintained. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively
rare.
3) If the redline changes are implemented, GOs are removed from R4,
thereby removing the obligation for GOs to maintain their connection
requirements. If GOs are included in FAC-001, they should be held
accountable to the same level as TOs and should be required to maintain
their connection requirements. Requiring a GO to maintain connection
requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would
initially be inexperienced in performing interconnection studies and would
benefit from regular and frequent review of their connection requirements
as experience and expertise are gained.
4) The revision to FAC-001-1 R2 may be problematic, depending on what
was intended. Under the revised requirement, the obligation to comply is
dependent on the execution of an agreement to evaluate reliability impacts
under FAC-002-1. However, FAC-002-1 does not clearly require the
execution of an agreement by the Generator Owner. FAC-002-1 only
requires the Generator Owner to “coordinate and cooperate on its
assessments with its Transmission Planner and Planning Authority”.
Accordingly if a Generator Owner coordinates without executing an
agreement to perform an assessment, compliance with FAC-001 R1 will not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
be required.
5) Manitoba Hydro would also like to point out that if the redline changes
are implemented, it will greatly increase the complexity of coordination
required under FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP).
The intent of the modifications to this standard is to address the requirements of the GO prior to the interconnection of the third
party to their Facilities. The reliability gap the SDT intends to close is the need for the GO to develop Facility connection
requirements prior to interconnection. The SDT does agree that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
The SDT also refers the commenter to the document titledProject 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document, which is posted on the project page. Specifically, see the last paragraph on page 4 and first two
on page 5.
Tennessee Valley Authority
No
Suggest that the overall structure of the standard be revised such that R1 R3 are applicable to the Transmission Owner (consistent with existing FAC001-0) and R4 (the new requirement) is applicable to the “applicable
Generator Owner”. See further comments below. Support the proposed
revisions to R1 and R4, but suggest R4 be returned to R3 (consistent with
existing FAC-001-0).R3 in the balloted standard should be returned to R2
(consistent with existing FAC-001-0) and only be applicable to the
Transmission Owner. R3.1 (or R2.1 if moved back) should be “fixed”, but it
may be beyond this SDT’s charge. The use of “above” in the FAC-001-0
standard, or the proposed reference to “Requirements R1 or R2” in the
proposed standard do not make sense in combination with the colon used
at the end of the requirement. Suggest that R3.1 (or 2.1 if moved back) be
revised as written below and all sub-requirements of R3.1 be elevated
(R3.1.1 becomes R3.2, R3.1.2 becomes R3.3, etc.).”R3.1 Performance
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
requirements and/or planning criteria used to assess system impacts.” R2 in
the balloted standard should become R4 and modified to incorporate the
connection requirements contained in R3 that can more reasonably be
expected of an “applicable Generator Owner”. For instance, an “applicable
Generator Owner” might simply have a connection requirement for a third
party that addresses coordination of system impact studies with the
appropriate Transmission Owner(s), in lieu of R3.1, R3.1.1, and R3.1.2.
Suggest that R2 (or R4 if moved below existing FAC-001-0 requirements) be
revised as written below.”R2 Each applicable Generator Owner that has
agreed to allow a third party Facility owner (Generation Facility,
Transmission Facility, or End-user Facility) to connect to the Transmission
system through use of pre-existing applicable Generator Owner Facilities
shall communicate it’s Facility connection requirements to the third party.
The applicable Generator Owner Facility connection requirements shall
address the following items: R2.1 Coordination of system impact studies
with the Transmission Owner. R2.2 Voltage level and MW and MVAR
capacity or demand at point of connection. R2.3 Breaker duty and surge
protection. R2.4 System protection and coordination R2.5 Metering....” Etc.
Response: Thank you for your comment. We gave the comment due consideration and agree that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the standard.
No change made.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
The intent of the draft language in FAC-001-1 is to provide guidance for
addressing the alleged reliability gap that exists between GO/GOPs that
own/ operate transmission facilities but are not registered as TO/TOPs. The
impact of the revised language will depend on the characterization of the
generator lead after the “third party “ connects to the existing generator
lead. IF the generator lead is owned by the TO utility after the third party
connection : The proposed DRAFT FAC-001 language suggests that within 45
days of a 3rd party having an executed Agreement to evaluate the reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
impact of interconnecting, the existing generator needs to document and
publish facility connection requirements. The proposed language suggests
that a third party can commandeer existing generators leads and
interconnect. A reclassification would be required because “third party”
power would flow through the downstream portions of the existing leads.
This introduces significant challenges for defining ownership / transfer of
installed assets as well as real property, easements, operational jurisdiction,
O&M cost responsibility, etc.
The FERC approved pro-forma Attachment
X Interconnection Agreement clearly states that the project Developer must
meet all Applicable Reliability Standards which means that all
requirements and guidelines of the Applicable Reliability Councils, and the
Transmission District to which the Developer’s Large Generating Facility is
directly interconnected. As an example, to accommodate this NERC
proposal, the FERC approved NYISO pro-forma tariff would need to be
revised to allow this “third party” use. The pro-forma interconnection tariff
also states that the Developer must provide updated project information
prior to the Facilities Study. The Facilities Study might not be made until
several years after the Interconnection Request /Feasibility Study is made
(“executed Agreement to evaluate the reliability impact of interconnecting”
in this proposed draft is akin to the Interconnection Request/Feasibility
Study). Placing the requirement to have the existing Generator Owner
publish reliability requirements for a potential “third party user”, without
the generator having any knowledge of the potential reliability outcomes or
asset transfer / ownership issues is not a reasonable expectation. The
interconnection of a third party to an existing generator lead would force
existing generators to revise their Interconnection Agreements with FERC.
The “third party”, would at a minimum, need to comply with the existing
Generators reliability obligations as specified in the Interconnection
Agreement.IF the third party connects to the GO owned generator lead, the
GO will be considered a TO:A TO would not be involved, other than review
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
of the SRIS and Facilities reports. The difficult thing for an existing GO
would be to prepare, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility, a document listing the requirements.
To allow for the above possibilities, the language for applicability of FAC001 to GO’s or GOP’s, should be :”Each applicable Generator Owner shall, at
least 60 days prior to execution of a Facilities / Class Year Study Agreement
to evaluate the reliability impact of interconnecting a third party Facility to
the Generator Owner’s existing Facility that is used to interconnect to the
Transmission System, document and publish its Facility connection
requirements to ensure compliance with NERC Reliability Standards and
applicable Regional Entity, sub regional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection
requirements.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Consolidated Edison Co. of NY, Inc.
No
The language for FAC-001 Requirement R2 should be:”This requirement
shall apply to each applicable Generator Owner. Generator Owner filings
must be made at least 60 days in advance of execution of the final
interconnection study agreement in the Planning Coordinator’s or
Transmission Planner’s study process.Each applicable Generation Owner
must publish its Facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Entity, sub regional,
Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.The evaluation of the reliability impact(s) of
interconnecting a third party Facility to the Generator Owner’s existing
Facility utilized for interconnection to the Transmission System must be
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
documented.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Unfortunately, the vital point of this requirement revolves around whether
or not a Generator Owner is compelled externally to allow access to their
interconnection facilities. If the GO is driving the connection for financial or
other business reasons, there is no reason they should not be responsible
for developing AND maintaining a facility connection requirements
document. Otherwise, when the local transmission system requirements
change for any reason, there will be no entity responsible to ensure that the
third party will conform as well.Conversely, if the GO should be compelled
to allow access to a third party, it is the responsibility of the “compeller” to
handle all the related reliability studies and documents. This may include
the development of a CFR which separates reliability tasks between the GO
and other entities - especially if a TSP registration is required. This ensures
that the Regional Entity, PUC, RTO, or other regulator must budget dollars
and resources directly related to their action - not cause them to be
directed to a GO.
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. However, the
issues you raise are beyond the scope of the SDT and its SAR. No change made.
PSEG
No
We revised this partial sentence to the following: “Each applicable
Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Transmission Facility that is used for connection
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
to the interconnected Transmission systems (under FAC-002-1), ...”- The
phrase “Generator Owner’s existing Facility that is used to interconnect to
the Transmission System” was changed to “Generator Owner’s existing
Transmission Facility that is used for connection to the interconnected
Transmission systems.” - “Transmission” was added before Facility to
exclude connections elsewhere; “Transmission System” was changed to
“Transmission systems” because while “Transmission” and “System” are
defined in the NERC Glossary, “System” means “A combination of
generation, transmission, and distribution components.” “Transmission
systems” do not have generation or distribution components, so a lower
case “system” is warranted. - In addition, the suggested phrase
“interconnected Transmission systems” (plural "systems") uses identical
language from FAC-002-1, except that we capitalized “Transmission.
Response: Thank you for your comment. The SDT has addressed the proposed change to applicability according to your comments.
The applicability section now reads: “Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect to the interconnected
Transmission systems.
The SDT has been informed that in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the
SDT’s attention that in most cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the
GO with FERC. Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain
the term “Transmission.”
Seattle City Light
Affirmative
Key points are that (1) an executed agreement is required before
evaluations of impacts are necessary and (2) this only applies when a third
party is connecting to the generating interconnection line.
Response: Thank you for your comment.
Electric Power Supply Association
Yes
All TO requirements for FAC-001-1 would apply if and when GO executes
an Agreement to evaluate the reliability impact of interconnecting a third
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
party Facility to its existing generation interconnection Facility. The
execution of the agreement is necessary to comply with FAC-002-1 and start
the compliance clock with the applicable regulatory authority. Thus as the
Project 2010-07 Standard Drafting Team (SDT) in its technical justification
has stated, “If, and only if, the existing owner of a generator
interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing
generation Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s
conclusion.The SDT has examined the issue regarding if future requests for
transmission service on the interconnection Facility and in doing so
acknowledged that when that Facility adopted open access and was
providing transmission service it would necessitate re-evaluation of the
need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary
agreement the SDT contemplates in its technical justification of FAC-001-1.
EPSA believes this serves as the necessary trigger for evaluation of
Requirements 2 and 4 under FAC-001-1 for GOs.
Response: Thank you for your comment.
American Wind Energy Association
Yes
AWEA appreciates that this standard specifies that it has limited
applicability. For instance, only those generators that have an executed
agreement with a third party wishing to interconnect must document and
publish Facility connection requirements. We believe the proposed 45-day
time window is a minimum for GO/GOP owners of generator lead lines to
provide this documentation following execution of such an agreement.
Anything less than 45 days could result in a burdensome and hard to meet
deadline for GO/GOP staff. However, AWEA believes that extending this
time window for publishing Facility connection requirements to 90 days
after an executed agreement would be beneficial. We believe this will allow
the GO/GOP owners of generator leads more time to coordinate with their
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
interconnecting Transmission Providers and will result in more reliable and
coordinated connection requirements for the generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO.
No change made.
SERC OC Standards Review Group
Yes
Please verify within the applicability section (4.2.1) you intended to use the
word “within” rather than some other wording.
Response: Thank you for your comment. The SDT intended it to read “Generator Owner with an executed Agreement to evaluate
the reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect
to the Transmission System.” This change has been made.
RES Americas Development
Yes
RES Americas and AWEA appreciate that this standard specifies that it has
limited applicability. For instance, only those generators that have an
executed agreement with a third party wishing to interconnect must
document and publish Facility connection requirements. We believe the
proposed 45-day time window is a minimum for GO/GOP owners of
generator lead lines to provide this documentation following execution of
such an agreement. Anything less than 45 days could result in a
burdensome and hard to meet deadline for GO/GOP staff. However, we
believes that extending this time window for publishing Facility connection
requirements to 90 days after an executed agreement would be beneficial.
We believe this will allow the GO/GOP owners of generator leads more time
to coordinate with their interconnecting Transmission Providers and will
result in more reliable and coordinated connection requirements for the
generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 1 Comment
Yes
We largely agree with the changes the drafting team made but believe
some additional changes are necessary. In section 4.2.1 of the Applicability
Section, “within” should be “with”. Because NERC’s Glossary of Terms
establishes that an Agreement can be verbal and not enforceable by law,
section 4.2.1 should be further modified to clarify that it is a legally
enforceable and fully executed Agreement. The language in R3 in
parenthesis after Generation Owner should be modified to “once required
by Requirement R2”. This makes it clearer that R3 does not apply until the
GO has an executed Agreement to evaluate a request by a third part to
interconnect.
No change made.
ACES Power Marketing Standards
Collaborators
Response: Thank you for your comment. We agree that “within” should be “with”. The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Southwest Power Pool Regional
Entity
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
American Electric Power
Yes
BP Wind Energy North America Inc.
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery Company LLC
Yes
Ameren
Yes
American Transmission Company
Yes
South Carolina Electric and Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 1 Comment
ReliabiltiyFirst
Entergy Services
Consideration of Comments: Generator Requirements at the Transmission Interface
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27
Organization
Yes or No
Question 1 Comment
Western Electricity Coordinating
Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power Administration
Consideration of Comments: Generator Requirements at the Transmission Interface
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28
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan for FAC-001-1?
Summary Consideration:
The vast majority of commenters supported the one year compliance time frame in the Implementation Plan. A few
commenters were concerned with this time frame and associated enforcement, in part based on similar issues addressed
in recent CANs. The SDT did its best to clarify its intent as follows:
The SDT’s intent is that the mandatory date (the date upon which the GO must be compliant with applicable
requirements and measures) be the first calendar day of the first calendar quarter one year after FAC-001-1’s approval.
The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the
mandatory date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those
requirements shall address items under R3.
No changes were made to the Implementation Plan.
Organization
Yes or No
Ingleside Cogeneration LP
(Occidental Chemical)
No
Question 2 Comment
Based upon similar issues addressed in Compliance Application Notices (CANs),
the drafting team needs to specify how the requirements apply to an in-place
“executed Agreement to evaluate the reliability impact of interconnecting a
third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System.” In the view of Ingleside
Cogeneration LP, if the Agreement takes effect even one day before FAC-001-1
does, requirements R2 and R3 do not apply. Without this clarification, it is
possible that NERC’s Compliance team will apply the requirements retroactively
- with minimum industry input.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
29
Organization
Yes or No
Question 2 Comment
address items under R3.
Southwest Power Pool
Regional Entity
No
No action is required unless a GO has an executed third-party agreement. If a
GO has an agreement, the standard already includes a 45-day timeframe for the
GO to document and publish its facility connection requirements.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
Southern Company
No
See our response to Question 9.
Response: See the SDT’s response to Question 9.
Manitoba Hydro
No
See question 1 comments.
Response: See SDT’s response to Question 1.
Cowlitz County PUD
Yes
Cowlitz PUD (District) registered as a Transmission Owner shortly before FAC001-0 became effective and was forced to file a Mitigation Plan in order to
facilitate compliance. The District successfully completed compliance
implementation and documentation in eight months. The proposed one year
compliance timeframe is sufficient.
Response: Thank you for your comment and support.
Seattle City Light
Yes
The proposed changes for FAC-001-1 state a 45 day period to complete the
evaluation. Not sure what the question is referring to regarding “ 1 year “?
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
American Wind Energy
Association / RES Americas
Development
Yes
Yes, since there is no exigent reason why this standard needs to be put in place
at once, we support the one-year compliance timeframe. We believe that it will
allow generators a reasonable time to comply with the requirement.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
PSEG
Yes
American Transmission
Company
Yes
Question 2 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
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32
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Constellation Power Source
Generation
Yes
Question 2 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
Entergy Services
ReliabiltiyFirst
Texas Reliability Entity
Consideration of Comments: Generator Requirements at the Transmission Interface
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33
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the switchyard,
generating station, or generating substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the fenced area of
the generating station switchyard…” We believe that the one mile length is a reasonable approximation of line of sight, and that
using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion on
the part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this qualifier for Generator
Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are
not necessary to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will be made as
Project 2007-07—Vegetation Management moves forward, do you support the proposed redline changes to FAC-003-X and FAC003-3?
Summary Consideration:
The SDT thanks all stakeholders for their comments and their over 85% approval for the FAC-003-X and FAC-003-3
changes posted for ballot in November 2011. Based on stakeholder feedback, the SDT has made the following changes:
-Added a clarifying reference to line of sight in the GO exemption in section 4.3.1.
-Corrected a typo in 4.3.1.2 of FAC-003-3.
-Changed “RE” to “Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally
supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability
benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
34
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight from the generating station switchyard
fence to the point of interconnection with a Transmission Owner’s Facility and is operated at 200 kV and above
and any lower voltage lines designated by the Regional Entity as critical to the reliability of the electric system in
the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond the fenced area of
the generating station switchyard to the point of interconnection with a Transmission Owner’s Facility or (2) do
not have a clear line of sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and are: Operated at 200kV or higher; or operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance that can be seen
by the average person without special instrumentation (e.g., binoculars, telescope, spyglasses, etc.) on a clear day.”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has been agreed
upon by the stakeholder body. In its Consideration of Comments report from the last formal comment period, which
ended on July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable approximation of line of
sight, and that using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion
and any discretion on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight
reference here, the SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Some stakeholders suggested changes that should have been submitted when Project 2007-07 was revising FAC-003-2,
because these suggestions dealt with the standard as a whole rather than the changes made by this SDT to ensure that
GOs are included in the standard’s applicability.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
35
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 3 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of
said line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other
lines. If the GO is only responsible for 0.2 miles, what is the technical basis to ignore
a mile? And would it be the first mile from the switchyard that is ignored, or is the
middle mile, or the last mile where it connects to the TO? Or could the GO decide?
Or could the GO pick sections of the line that amount to a mile that they can ignore?
This seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
36
Organization
Yes or No
Question 3 Comment
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT chose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
Wisconsin Public Service Corp
Electric Cooperative
Negative
R1.2 refers to an encroachment due to a fall in. This is confusing because according
to the dictionary “Webster’s II” encroachment reads: “to intrude gradually”, and a
‘fall in’ is not usually gradual.
Response: Thank you for your comment. This is outside the scope of the SAR. The SDT reviewed comments submitted as part of the
Project 2007-07 effort and did not find this comment had been submitted.
Wisconsin Public Service Corp.
Negative
The concern with the proposed wording is that many generating station may not
have a “generating station switchyard” as implied by the proposed wording. Often
the generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers the
now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
37
Organization
Yes or No
Question 3 Comment
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: A two
kilometer distance from the controlled area perimeter.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Florida Reliability
Coordinating Council
Negative
There is no technical justification for excluding 1 mile beyond the fence in the
applicability of generators.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Southern Company
No
 All of these comments pertain to FAC-003-3:
1) We suggest referring to the Implementation Plan in the Effective Date sub-section
of Section A of the standard rather than repeating the content of the
Implementation Plan in the standard. There exists unnessary duplication with
including the information in both places.
2) We suggest simplifying the purpose statement to more succinctly say the intent,
for example: "To maintain a reliable transmission system by managing vegetation
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
38
Organization
Yes or No
Question 3 Comment
located on transmission rights of way to minimize vegetation encorachments and
thereby minimize the risk of vegetation related outages". If this change is not
acceptable, at least change the phrase "preventing the risk" to "minimizing the risk".
3) We feel that the Enforcement paragraphs between 4.3.1.3 and 5.0 seem to be
out of place. Those paragraphs don’t belong in this location - consider moving them
to Section C. Compliance. The fourth paragraph belongs in the background section.
4) We suggest moving the background section to Section F. "Associated
Documents". It gets in the way of getting to the requirements of the standard.
5) We suggest moving Table 2 of the "Guideline and Technical Basis" document into
R1, since it seems to be the only part of the document that is enforceable. Further
we suggest that the Guideline and Technical Basis document be removed from the
standard. The inclusion of this document in the standard makes the standard
unweildy.
6) We suggest reordering the words in R1 to more clearly state the requirement.
Please consider this rephrasing: "For lines which are either an element of an IROL or
an element of a Major WECC Transfer Path, each applicable TO and applicable GO
shall manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) when operating within their Rating during all Rated Electrical Operating
Conditions of the types shown below:..." (remainder is unchanged).
7) We suggest reordering the words of R2 to more clearly state the requirement.
Please consider the this rephrasing: "For lines which are neither an element of an
IROL nor an element of a Major WECC Transfer Path, each applicable TO and
applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within its Rating and during all Rated Electrical
Operating Conditions of the types listed below:..." (remainder is unchanged).
8) On Page 11 of the posted clean draft standard, is the reference to the previous
footnote 2 correct? We recommend eliminating footnotes where possible to
minimize redirections.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
39
Organization
Yes or No
Question 3 Comment
9) The Rationale text-box on page 13 of the clean version of FAC-003-3 overlaps
some of the text of footnote #6.    
Response: Thank you for your comment.
With respect to your suggestion regarding the implementation plan, the SDT simply followed the NERC-mandated document
guidelines. Making the change you suggest would deviate from that process and thus the SDT has not made it.
With respect to comments 2-8, any standard changes that go beyond making a standard applicable to a GO or GOP are beyond the
scope of this SDT. Any redline changes the SDT has made within standards were made to clarify or qualify the GO or GOP
applicability. These comments would have been more appropriate to make during the comment period for Project 2007-07
Vegetation Management, the project that revised the version of FAC-003 from which this SDT is working.
We have modified the rationale box on page 13 so that it does not overlap with the text of footnote 6.
Dominion
No
Dominion suggests in FAC-003-X; 4.3.1. Regional Entity be changed to RE as listed in
4.2.1 for consistency. Also Regional Entity is used throughout the rest of the
document, suggest using RE for consistency overall. Dominion suggests in FAC-003-3;
4.3.1. adding station to the following “ Overhead transmission lines that extend
greater than one mile or 1.609 kilometers beyond the fenced area of the generation
station switchyard and are” to show consistency as it is written in FAC-003-X
4.3.1.Further, Dominion is concerned that the technical justification characterized
the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard) as “approximate line of sign [sic] from a fixed point”
and notes that this line of sight may be limited by local terrain. Where line of sight of
the radial corridor is limited on a clear day due to terrain, the one mile exemption
must be limited in distance to no more than the line of sight on a clear day beyond
the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
40
Organization
Yes or No
Question 3 Comment
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Exelon
No
FAC-003 - Exelon supports the one mile length qualifier, but feels that additional
clarification is needed to determine the points of demarcation. There are too many
differing physical configurations to use a “fence line” as a determination of
applicability. Suggest that the tie line length be defined as “from the Generator Step
up Transformer GSU to the point of interconnection between the GO and TO owned
equipment.” Also suggest that the standard define what constitutes a generation
station switchyard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Ingleside Cogeneration LP is very concerned that the attempt to develop “brightline” criteria to assign applicability to either version of FAC-003 is misplaced. As seen
with NERC’s recent proposed directive related to Generator-Transmission
interconnections, those thresholds can be arbitrarily reduced based upon regulators
aversion to risk - not scientific evidence. (As it stands today, NERC has proposed any
interconnection facility operating at 100 kV or higher and greater than 3 spans in
length be applicable - which is even stricter than the TO thresholds in FAC-003.)This
would suggest that a reliability assessment consistent with the TPL standards must
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
41
Organization
Yes or No
Question 3 Comment
be the determining factor. If the Planning Coordinator or Transmission Planner can
show that the Generator-Transmission interconnection could contribute to a
violation of an SOL or IROL, then a vegetation management program may be in
order.Furthermore, there needs to be some level of common sense applied if a GOTO interconnection is located in an area where vegetation clearance is never an
issue. A one-size-fits-all requirement based upon vegetation growth in the subtropics, should not automatically apply in the desert. In our view, every dollar spent
to control vegetation in an arid climate is one less dollar available to purchase
advanced telemetry, AGC systems, and other items which have a far greater impact
on reliability.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
The SDT also took into consideration the stakeholder comments submitted and believes this exemption adequately addresses the
reliability impact for a majority of the Facilities, while balancing the efforts necessary to support the standard from all entities.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in this project. If a
Generator Owner is required to register as a TO, all the Requirements applicable to a
TO should apply. There is no need to change specific Reliability Standards to allow
the Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT also
refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface Background
Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
42
Organization
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes or No
Question 3 Comment
No
Suggest in FAC-003-X; 4.3.1. that Regional Entity be changed to RE as listed in 4.2.1
for consistency. Also Regional Entity is used throughout the rest of the document,
suggest using RE for consistency.In FAC-003-3; 4.3.1. add station to the following: “
Overhead transmission lines that extend greater than one mile or 1.609 kilometers
beyond the fenced area of the generation station switchyard and are” to show
consistency as it is written in FAC-003-X 4.3.1.The technical justification
characterized the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced
area of the generating station switchyard) as “approximate line of sight [sic] from a
fixed point” and noted that this line of sight may be limited by local terrain. Where
line of sight of the radial corridor is limited on a clear day due to terrain, the one mile
exemption must be limited in distance to no more than the line of sight on a clear
day beyond the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
MRO NSRF
No
The NSRF agrees with the drafting committees desire to eliminate arbitrary and
capricious behavior of auditors and industry staff by precisely defining the point at
which measurement starts for the length of transmission line. The concern the NSRF
has with the proposed wording is that many generating station may not have a
“generating station switchyard” as implied by the proposed wording. Often the
generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
43
Organization
Yes or No
Question 3 Comment
the now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: NSRF
recommends a two kilometer distance from the controlled area perimeter. Our
assessment is that an individual of average height would have a line of site of
approximately 4 Kilometers. Therefore, we recommended a distance of 2 kilometers
from the Controlled Area of the plant to provide margin. The revised applicability
statement would read as follows: “Generator Owner that owns an overhead
transmission line(s) that extends greater than 2.0 kilometers beyond the Controlled
Area of the generating station up to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in
the region. Furthermore we applaud the committee for using the metric system to
identify the acceptable distance for this standard and urge it to remove all
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
44
Organization
Yes or No
Question 3 Comment
references to English units. We strongly suggest this drafting team and all future
drafting team abandon the anachronistic English measurement system. This archaic
system, based on the length of an average barley corn, should be abandon in all
scientific and engineering endeavors.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Southwest Power Pool
Standards Development Team
No
There is a possibility of some conflict with the Bulk Electric System Definition. This
should be consistent with the Transmission Owner requirements if the lead is
determined part of the BES.
Response: Thank you for your comment. The SDT intended this standard to be applied to Facilities of GO and TO equally, with the
exception of the distance exemption for a generator interconnection Facility. The SDT also notes that FAC-003-2 (approved by the
NERC’s Board of Trustees on Nov. 3, 2011) does not rely upon the BES definition to determine the facility to which this standard
applies (200 kV or higher, or IROL or WECC Transfer Path).
South Carolina Electric and
Gas
No
There should be no qualifying exemption to FAC-003 for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
45
Organization
Yes or No
SERC Planning Standards
Subcommittee
No
Question 3 Comment
We believe there should be no exemption for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
PSEG
No
Infigen Energy US
Affirmative
Infigen finds the DST supporting details regarding FAC-003-X to be appropriate. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
Seattle City Light
Affirmative
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
RES Americas Development /
American Wind Energy
Association
Yes
Applying the vegetation management requirements to only generator lead lines that
extend more than “one mile beyond the fenced area of the generating station
switchyard” strikes a reasonable balance among the many stakeholder positions
expressed on this topic. We think that as this criterion recognizes that there is little
need for a vegetation management plan for shorter lines, it should explicitly state
that this is true for all such facilities with lines of that length or smaller.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
46
Organization
Yes or No
Texas Reliability Entity
Yes
Question 3 Comment
In the description of the “second effective date” in FAC-003-X there is an erroneous
reference to “Requirement R3,” which should be corrected to “Requirement R1.”
Response: Thank you for your comment and support. This conforming change was made.
Seattle City Light
Yes
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
ACES Power Marketing
Standards Collaborators
Yes
We support the changes to FAC-003 suggested by the drafting team because we
believe the drafting team has provided the best solution in face of a difficult
problem. However, in general, we do not support registration of GOs and GOPs as
TOs and TOPs or applicability of any TO/TOP requirements to the GO/GOP simply
because they have a radial interconnection greater than one mile in length. While
there may be some generators that own interconnecting facilities of significant
length operated at a significant voltage that could impact BES reliability, we do not
believe that the number of generating facilities that fit into that category is
significantly large. When one considers that the majority of generators are still
owned and operator by utilities that are also registered as a TO and TOP, there is
only a minority subset of generators left that could be considered. NERC has the
registration for this remaining set of generators and could use the data to evaluate
how many of this remaining subset have interconnections owned by the generator
that are substantial enough to affect reliability. It seems that NERC could determine
the boundaries of this problem before registering anymore GOs and GOPs as TOs and
TOPs or before applying additional requirements through this effort on the GOs and
GOPs.
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
47
Organization
Yes or No
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Regional Entity
Yes
Florida Municipal Power
Agency
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Question 3 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
48
Organization
Yes or No
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 3 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of
NY, Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
49
4.
Do you support compliance timeframe for Generator Owners as included and explained in the Implementation Plans for
FAC-003-X?
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-X.
One commenter found a typo in the effective dates section of FAC-003-X, where one section referenced R3 when it
should have referenced R1. That has been corrected in both the standard and the Implementation Plan.
A few stakeholders thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Beyond the corrected typo, no changes were made.
Organization
Yes or No
Ameren Services
Negative
Question 4 Comment
The 2 year compliance time line is far too long. There is significant industry evidence
that was developed in the drafting of Version 2 that supports a one year compliance
time-line for new lines. This is evidenced in Version 2. Thus there is no basis for the 2
years.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Texas Reliability Entity
No
A compliance timeframe for the applicable GOs of two years is too long and the
scenario used as a basis provides no timing specifics or details. Moreover, the 12
months for an existing transmission line operated at 200kV or higher which is newly
acquired by an asset owner and which was not previously subject to this standard is
arguably the same situation as an applicable GO but the applicable GO has an
additional 12 months to come into compliance.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so. The SDT does not believe
that a TO’s acquisition of a new asset is the same as applying new requirements to a GO.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the
drafting team needs to specify when the first vegetation management inspection
quarterly report, and any other requirement with an assigned interval in FAC-003-3 or
FAC-003-X. Even if the decision is to adopt the same criteria proposed in CAN-0012,
the industry is better served with a clear distinction made up front.
Response: Thank you for your comment. This is a comment that is outside the scope of the SDT, and in fact deals with a larger body of
standards than just FAC-003. No change made.
PSEG
No
It’s no longer applicable.
Response: Thank you for your comment. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2
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Organization
Yes or No
Question 4 Comment
– Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Manitoba Hydro
No
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southwest Power Pool
Standards Development Team
No
The effective dates should be consistent with the original standard. If there is a
reason for the extension we would like to know why.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Southern Company
Yes
The development of a working TVMP will take some time to initialize. The 1 year time
frame for R3 is appropriate. The 2 year time frame for all other requirements is
appropriate.
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
Seattle City Light
Yes
The explanation deals with the fact that there are simultaneous revisions of FAC-003
underway by two different teams.
Response: Thank you for your comment and support.
MRO NSRF
Yes
There may be a typographical error on the effective date. As currently drafted the
standard states: In those jurisdictions where regulatory approval is required,
Requirement R1 applied to the Generator Owner becomes effective on the first
calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities where such explicit
approval for all requirements is required. In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption. Should it be worded
as follows? In those jurisdictions where regulatory approval is required, Requirement
R1 applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
Response: Thank you for your comment. The SDT agrees with you. “Requirement R3,” will be corrected to “Requirement R1.”
RES Americas Development/
American Wind Energy
Association
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this
standard needs to be put in place at once, we support the proposed compliance
timeframe. We believe that it will allow generators a reasonable time to comply with
the requirement.
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
Yes
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Organization
Yes or No
Question 4 Comment
America Inc.
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Western Electricity
Coordinating Council
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Organization
Yes or No
Question 4 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of different scenarios that could play out
with respect to the filing and approvals of FAC-003-2 and FAC-003-3. Do you support this approach? If there are other scenarios
that the SDT needs to account for, please suggest them here.
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-3.
One commenter thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Some stakeholders expressed confusion about the relationship between FAC-003-3 and the recently BOT-approved FAC003-2. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission
Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff
will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for
both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERCapproved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X
through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
All stakeholders should note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but
stakeholders should not vote as though they are choosing one or the other. As stated above, the SDT plans to present
FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X ready to submit to the Board if, for some
reason, neither FAC-003-2 nor FAC-003-3 are approved by FERC. Members of the ballot body should vote on the merits of
each version of FAC-003 individually. In other words, stakeholders who support adding GOs to the applicability of FAC003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Manitoba Hydro
No
Question 5 Comment
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southern Company
No
We believe that a standard development process should not have parallel paths where
the same version is being modified by multiple teams. The uncertainty in which
development path leads to confusion in the industry and ultimately proves to have
wasted come resources for the path that does not come to fruition.
Response: Thank you for your comment. While the SDT agrees this is not preferable, it was necessary given the urgency of both
projects. The SDT did the best it could to describe the scenarios and reasons for posting multiple versions.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation Management (developed under Project
2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities.
The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and
FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has
elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be
ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration agrees that the SDT’s approach is thorough. We are far more
concerned about FAC-003’s applicability criteria and implementation time frame at
this point - as stated in our responses to questions 3 and 4.
Response: Thank you for your comment and support. Please refer to the SDT’s responses to Questions 3 and 4.
ACES Power Marketing
Standards Collaborators
Yes
With recent NERC BOT approval of the FAC-003-2 standard, the drafting team should
continue to monitor the standard progress with FERC and make necessary
adjustments to the implementation plan.
Response: Thank you for your comment. The SDT acknowledges that FAC-003-2 was recently approved by the BOT. The SDT does not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
see the need to revise the GO implementation plan, as it already accounts for a number of scenarios that could occur based on how
FERC handles the filing of FAC-003-2.
Ameren
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of said
line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other lines.
If the GO is only responsible for 0.2 miles, what is the technical basis to ignore a mile?
And would it be the first mile from the switchyard that is ignored, or is the middle
mile, or the last mile where it connects to the TO? Or could the GO decide? Or could
the GO pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
exceeds the distance, the entire Facility is subject to the requirements of the standard.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
The SDT choose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
PSEG
Yes
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Wind Energy
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
Association
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
RES Americas Development
Yes
Sempra Generation
Yes
Entergy Services
Yes
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Organization
Yes or No
Xcel Energy
Yes
Cowlitz County PUD
Yes
Texas Reliability Entity
Yes
Constellation Power Source
Generation
Yes
Tennessee Valley Authority
Yes
Question 5 Comment
Southwest Power Pool
Regional Entity
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Consideration of Comments: Generator Requirements at the Transmission Interface
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6. In its technical justification document, the SDT reviews all standards that had been proposed for substantive modification in the
Ad Hoc Group’s original support and explains why, with the exception of FAC-003, modifying them would not provide any
reliability benefit. Do you support these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Summary Consideration:
The SDT thanks all stakeholders for their comments.
A few commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit reference to a
generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing revisions to PRC-005-1a and
will post them soon.
Many commenters encouraged the SDT to reexamine the standards and requirements that FERC and NERC applied to
GOs and GOPs in their Milford/Cedar Creek order and draft compliance directive regarding generator leads. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider
the content of the proposed directive.
Based on stakeholder comments, the SDT expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft
compliance directive. After another thorough review of these standards, the SDT continues to believe that there are clear
and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 6 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
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Organization
Yes or No
Question 6 Comment
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Texas Reliability Entity
No
Our negative votes on FAC-003 reflect our concern that this project has not
considered all of the applicable standards. Why did the SDT choose to only review the
Ad Hoc Group’s standards when there have been multiple registration appeals in
which FERC and NERC have repeatedly cited specific additional TO/TOP standards that
were determined to be applicable to GO/GOPs? This SDT project would serve a
tremendous value to the ERO and in particular industry if it were to address the
technical aspects of the following FERC ordered applicable standards: PRC-001-1 R2,
R4; PRC-004-1 R1; TOP-004-2 R6; PER-003-1 R1; FAC-003-1 R1, R2; TOP-001-1a R1 and
FAC-004-2 R2. The SDT team should analyze the FERC orders, the applicable
standards indicated, and the circumstances and facts involved, and technically justify
why no reliability gap exists if these standards are not applied to GO interface
facilities. The SDT should include more “technical” information in its technical
justification document. For example, in regards to TOP-004-2 R7, the SDT technical
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Organization
Yes or No
Question 6 Comment
justification states that there is no reliability gap because, “. . . because an operator
has a fiduciary obligation to protect a Facility for which it is operationally
responsible.” An entity having a fiduciary obligation is not a technical justification of
why a reliability gap does not exist. Moreover, by that logic there would be no need
for many standards because every registered entity has a fiduciary obligation to
protect its facilities.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
We would like to clarify, in response to the comment concerning TOP-004-2 R7, that in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface” the SDT also stated “FAC-008-1—Facility Ratings
Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for establishing a ratings
methodology and communicating facility ratings to the Reliability Coordinator, Planning Authority, Transmission Planner, and
Transmission Operator is for use in reliable planning and operation of the Bulk Electric System.”
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
PSEG
No
PRC-005-1 - Transmission and Generation Protection System Maintenance and
Testing was recommended by the Ad Hoc Group for modification, but not addressed
to the technical justification document. It should be.
Response: Thank you for your comment. We have reviewed PRC-005-1a and believe that the wording in R1 and R2 of that standard
require the same explicit reference to a generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing
revisions to PRC-005-1a and will post them soon.
Florida Municipal Power
No
see comment to Question 7
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Organization
Yes or No
Question 6 Comment
Agency
Response: See the SDT’s response to Question 7.
Manitoba Hydro
No
See Question 7 comments.
Response: See the SDT’s response to Question 7.
MRO NSRF
No
The NSRF has one concern with the current justification and definitions. At some
point, if enough interconnections are made to generator outlet leads in accordance
with FAC-001, the original generator operator will be a Transmission Operator and a
Transmission Owner. This point in time needs to be explicitly defined by the drafting
team.
Response: The SDT cannot act on this comment. Registration is outside the scope of this SDT and resides with NERC and the Regional
Entity.
Manitoba Hydro
If the drafting team intends to limit the scope of FAC-001-1 to GO owned radial
generator interconnection facilities that are not deemed BES transmission and
therefore would not require the registration of the GO as a TO, Manitoba Hydro
disagrees with the proposed changes to FAC-001-1 as Generator Owners may not
have the models or expertise to perform interconnection studies to determine if
there is an impact on the Transmission Network. This concern is echoed in the
technical justification document provided by NERC: ‘the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third part
to interconnect, have the necessary expertise to conduct the required interconnect
studies to meet this standard... the Generator Owner will have to acquire such
expertise. How the Generator Owner chooses to do so is not for the SDT to
determine.’ Although it may not be for the SDT to determine how a GO obtains
technical expertise, ensuring that such expertise is acquired before a GO conducts the
required interconnection studies should be a concern to NERC as this directly affects
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Organization
Yes or No
Question 6 Comment
the reliability of the BES. As a result, all interconnection requests should be
implemented by the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User facility as the
TO is in the best position to set unbiased connection requirements to ensure the
reliability of the BES is maintained. If the scope of FAC-001-1 also applies to GO
owned BES transmission facilities, Manitoba Hydro strongly believes that the
Compliance Registry should apply and the GOs should be required to register as a TO
and abide by all applicable standards to that functional type. There is no need to
change specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards, including the
protection standards, are met so the reliability of the BES is maintained. At this time,
this would not lead to a large number of extra registrations since, as stated in the
technical justification document, ‘interconnection requests for Generator Owner
Facilities are still relatively rare.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs. The SDT does agree that upon interconnection of a third party, other standards or registrations
may apply as appropriate.
Electric Power Supply
Association
Affirmative
All TO requirements for FAC-001-1 would apply if and when GO executes an
Agreement to evaluate the reliability impact of interconnecting a third party Facility
to its existing generation interconnection Facility. The execution of the agreement is
necessary to comply with FAC-002-1 and start the compliance clock with the
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Organization
Yes or No
Question 6 Comment
applicable regulatory authority. Thus as the Project 2010-07 Standard Drafting Team
(SDT) in its technical justification has stated, “If, and only if, the existing owner of a
generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation
Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s conclusion. The SDT
has examined the issue regarding if future requests for transmission service on the
interconnection Facility and in doing so acknowledged that when that Facility adopted
open access and was providing transmission service it would necessitate re-evaluation
of the need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary agreement
the SDT contemplates in its technical justification of FAC-001-1. EPSA believes this
serves as the necessary trigger for evaluation of Requirements 2 and 4 under FAC001-1 for GOs.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen supports the FAC-001-1 technical analysis by the Project 2010-07 SDT, which
states in part that “If, and only if, the existing owner of a generator interconnection
Facility has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply”. We agree with the SDT’s reasoning that if the owner of
the existing generator interconnection Facility agrees, or is compelled to allow a third
party to interconnect, but can do so using existing agreements, contracts, and/or
tariffs [to avoid requiring additional executed Agreement(s)], this is the most prudent
and effective way to manage this process with continuity. In order to evaluate the
reliability impact of interconnecting a third party Facility to the Generator Owner’s
existing Facility more expediently, it can avoid having to develop its own connection
requirements or perform additional impact studies, to the extent possible. We find it
reasonable to negotiate with the existing Transmission Owner, Transmission Planner,
and/or Transmission Service Provider to manage this requirement, utilizing their
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Organization
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Question 6 Comment
existing processes and Agreements for the purpose of fulfilling FAC-001-1.
Response: Thank you for your comment and support.
Southern Company
Yes
Additional responses are needed to justify the exclusion of the list of requirements
and standards found in the recent FERC order denying the rehearing request of the
Compliance Registry Appeals of Cedar Creek and Milford. (135 FERC Para. 61,241).
Please see our response to Question 10 for a detailed discussion on this
topic.   
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
Constellation Power Source
Generation
Yes
Constellation supports the SDT justifications and offers additional information in our
response to question 10.
Response: Thank you for your comment and support.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration LP believes the SDT has spent a significant amount of time and
effort to demonstrate that only FAC-001, FAC-003, and PRC-004 need to be modified
to address any reliability gaps that may exist related to the GO-TO interconnection.
We agree that the other standards/requirements identified by the Ad Hoc Group are
covered elsewhere.
Response: Thank you for your comment and support.
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Organization
Yes or No
American Wind Energy
Association
Yes
Question 6 Comment
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
RES Americas Development
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
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Organization
Yes or No
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Yes
Question 6 Comment
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Question 6 Comment
Gas
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Independent Electricity
System Operator
Ameren
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
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Question 6 Comment
Tennessee Valley Authority
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7. The SDT is attempting to modify a set of standards so that radial generator interconnection Facilities are appropriately accounted
for in NERC’s Reliability Standards, both to close reliability gaps and to prevent the unnecessary registration of GOs and GOPs at
TOs and TOPs. Does the set of standards currently posted achieve this goal?
Summary Consideration:
The SDT thanks all stakeholders for their comments. Most commenters support the SDT’s work and agree that the set of
standards for which the SDT has proposed modification ensure that radial generator interconnection Facilities are
appropriately accounted for in NERC’s Reliability Standards.
One commenter continues to express confusion about the scope of the SDT’s work in general. The SDT reminded this
commenter that its scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with
ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it
should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
transmission entity (TO/TOP). Through its deliberations, the SDT came to the conclusion that an interconnection Facility
owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT. The SDT also refers the commenter to the document titled Project
2010-07: Generator Requirements at the Transmission Interface Background Resource Document (specifically, the last
paragraph on page 4 and first two on page 5). The SDT has proposed the modification of a select set of standards so that
they apply to GOs and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been
widely supported by the stakeholder body. The SDT does agree that upon interconnection of a third party, other
standards or registrations may apply as appropriate.
One commenter asked the SDT to specify what it means by “radial.” By “radial generator interconnection Facilities,” the
SDT means sole-use Facilities (see posted examples under “Supporting Materials”) – that is, a Facility used to connect one
or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
A few commenters suggested that the SDT address those standards cited by FERC and NERC in related projects. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process. However, based on staekolder
comments, the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include
any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
After another thorough review of these standards, the SDT continues to believe that there are clear and technical
reliability-based reasons that support not adding GO and GOP requirements to these standards.
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One commenter suggested that the SDT include the GO in TOP-004-2 R6, but the SDT continues to maintain that no gap
exists because TOP-002-2 R3 already requires the GO to coordinate with its host BA and TSP, who in turn are required to
coordinate with their TOPs.
One commenter pointed out that the Data Retention section of the proposed PRC-004-2.1a also requires modification to
include the generator interconnection Facility. The SDT agrees and made this change.
Organization
Yes or No
Manitoba Hydro
Negative
Question 7 Comment
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
2) Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry
and only having a limited set of standards apply to the GOs ‘interconnection facilities’
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
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Question 7 Comment
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Manitoba Hydro
Negative
Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry and
only having a limited set of standards apply to the GOs ‘interconnection facilities’ If a
Generator Owner wants to own transmission facilities and it falls under the definition
of a Transmission Owner under the NERC Registry Criteria, then all the Requirements
applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions.
Reliability gaps would be better closed if select GOs and GOPs simply registered as
TOs and TOPs. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document, ‘interconnection
requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The SDT has proposed the modification of a select set of standards so that they apply to GOs
and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the
stakeholder body. The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as
appropriate.
PSEG
No
It would be helpful if the SDT defined what it means by the term “radial generator
interconnection Facilities.” Does it mean interconnection Facilities that under Normal
Clearing for a fault do not interrupt flows on other BES Elements? This is also
confusing because of the radial exclusion included in the BES definition work in
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Question 7 Comment
Project 2010-17. That definition would allow part of a three-terminal circuit to be
excluded from the BES, while the other parts are included in the BES.
Response: Thank you for your comment. By “radial generator interconnection Facilities,” the SDT means sole-use Facilities (see posted
examples under “Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated
by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO/GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside
the scope of this SDT.
Texas Reliability Entity
No
See comment 6.
Response: See the SDT’s response to Question 6.
Manitoba Hydro
No
The SDT’s proposed modifications gives special treatment to the Generator Owner in
that it allows the Generator Owner TO status for a couple of standards (FAC-001, FAC003 and PRC-004), but exempts the Generator Owner from many of the standards
applicable to a TO. The NERC Registry Criteria defines the various functional entities.
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
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GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Southwest Power Pool
Regional Entity
No
The Technical Justification document did not review the standards FERC identified in
paragraphs 71 and 87 of 135 FERC ¶ 61,241 ORDER DENYING APPEALS OF ELECTRIC
RELIABILITY ORGANIZATION REGISTRATION DETERMINATIONS. The SDT needs to
review these standards to determine if changes are needed; otherwise, FERC will
require registration of GOs and GOPs as TOs and TOPs to address reliability gaps. If
the SDT determines no changes are needed to these FERC-identified standards, they
should provide justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives) within the standards process. However, based on your and other comments, we have
expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards,
the SDT continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP
requirements to these standards.
Southern Company
No
We don’t believe the effort realizes the goal because 1) it is inclusive of FAC-001 that
does not need any modifications and 2) the effort needs to reinforce the appropriate
justification not to include the additional standards FERC has identified in their Cedar
Creek and Milford Orders.
Response: The SDT thanks you for your comment. The SDT believes that comment (1) is a complex issue and did its best to outline
how it arrived at its position in the document titled “Technical Justification: FAC-001-1.”
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As for comment (2), the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that don’t
include explicit directives) within the standards process. However, based on your and other comments, we have expanded our
technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
Western Electricity
Coordinating Council
No
WECC casts an affirmative vote for the SDT proposal as a necessary but not sufficient
step in addressing the GOTO matter. WECC, NERC, and the other Regions developed
a subset of Standards and Requirements that were considered necessary to address
potential gaps for transmission interconnection facilities and operations to be
included in a proposed NERC Directive, which is expected to issue by year-end. The
subset of requirements developed for the proposed NERC Directive were informed by
the applicable FERC Orders. Consequently, it is important that the SDT address the
comparative reliability risks between the proposed NERC Directive List and the SDT
Proposal to assure that reliability gaps will not result from the SDT proposal. Please
see NERC’s proposed Directive for the rationale and technical justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
However, based on your and other comments, we have expanded our technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance
directive. After another thorough review of these standards, the SDT continues to believe that there are clear and technical reliabilitybased reasons that support not adding GO and GOP requirements to these standards.
Florida Municipal Power
Agency
FMPA believes that TOP-004-2 R6.2 ought to also be addressed in the standards as
applicable to GOPs. The requirements reads:R6. Transmission Operators, individually
and jointly with other Transmission Operators, shall develop, maintain, and
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Question 7 Comment
implement formal policies and procedures to provide for transmission reliability.
These policies and procedures shall address the execution and coordination of
activities that impact inter- and intra-Regional reliability, including:R6.2. Switching
transmission elements.Although planned outages are covered in other standards
applicable to a GOP, switching to close / synchronize a generator back to the system is
not specifically covered in the standards. Some have argued that TOP-002-2 R3 causes
GOPs to coordinate its current day plans with the TOP; however, the name of the
standard is “Transmission Operations Planning” and therefore implies the availability
of the generator and related equipment and not necessary implies the policies and
procedures for switching operations; which includes synchronization. FMPA cannot
imagine a generator that would not have such switching / synchronization policies
and procedures coordinated with its interconnecting TOP; as such would normally be
required through a Large Generator Interconnection Agreement through a pro forma
OATT; however, FMPA is not aware of any instance in the standards that covers this.
As such, FMPA recommends including TOP-004-2 R6.2 as being applicable to a GOP.
Response: Thank you for your comment. We don’t agree that the gap exists because TOP-002-2 R3 already requires the GO to
coordinate with its host BA and TSP, who in turn are required to coordinate with their TOPs.
Manitoba Hydro
If the redline changes are implemented, GOs are removed from R4, thereby removing
the obligation for GOs to maintain their connection requirements. If GOs are included
in FAC-001, they should be held accountable to the same level as TOs and should be
required to maintain their connection requirements. Requiring a GO to maintain
connection requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would initially
be inexperienced in performing interconnection studies and would benefit from
regular and frequent review of their connection requirements as experience and
expertise are gained.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
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Question 7 Comment
in the document titled “Technical Justification: FAC-001-1.”
SERC OC Standards Review
Group
Please list the set of standards are you referencing.
Response: The SDT is referring to those standards posted for comment (FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1).
Constellation Power Source
Generation, Inc.
Affirmative
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. Please see more detailed comments submitted in the Project 201007 comment form submitted on November 18, 2011.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen finds the SDT supporting measures and analysis regarding FAC-003-3 to be
appropriate, and believes that it is prudent for Generation Owners and Transmission
Owners to manage vegetation maintenance records/inspections accordingly. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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Question 7 Comment
significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
Affirmative
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
The SDT agrees with your comment regarding the language in the Data Retention section and has modified that section as follows:
“The Transmission Owner, and Distribution Provider that own a transmission Protection System and the Generator Owner that owns a
generation or generator interconnection Protection System…”
Southwest Transmission
Cooperative, Inc. / ACES
Power Marketing
Affirmative
We largely support the changes made by drafting team because we believe the
drafting team has provided the best solution in face of a difficult problem. However,
in general, we do not support registration of GOs and GOPs as TOs and TOPs or
applicability of any TO/TOP requirements to the GO/GOP simply because they have a
radial interconnection greater than one mile in length. While there may be some
generators that own interconnecting facilities of significant length operated at a
significant voltage that could impact BES reliability, we do not believe that the
number of generating facilities that fit into that category is significantly large. When
one considers that the majority of generators are still owned and operator by utilities
that are also registered as a TO and TOP, there is only a minority subset of generators
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left that could be considered. NERC has the registration for this remaining set of
generators and could use the data to evaluate how many of this remaining subset
have interconnections owned by the generator that are substantial enough to affect
reliability. It seems that NERC could determine the boundaries of this problem before
registering anymore GOs and GOPs as TOs and TOPs or before applying additional
requirements through this effort on the GOs and GOPs. Subjecting a GO/GOP to any
TO/TOP standards requirements should require a clear demonstration f the reliability
gap in each instance. Some additional changes are necessary to FAC-001.
Response: Thank you for your comment and support. We are unsure as to what changes to FAC-001 you feel are necessary unless you
are referring to comments stated previously.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Although the SDT is nearing conclusion on the closing of reliability gaps, the
unnecessary registration of GOs and GOPs as TOs and TOPs is far from resolved in our
view. Ingleside Cogeneration’s concern is based upon NERC’s recent proposal to
dictate an interim GO-TO interconnection solution which completely bypasses the
Standards Development Process. Frankly, it seriously brings to question the nature of
the consensus-driven process - which appears to be moving in a dictatorial direction.
Response: Thank you for your comment and support.
American Wind Energy
Association
Yes
AWEA believes that the standards modifications proposed by the SDT should address
any genuine reliability gap with regard to generator lead lines, rather than just
perceived but unsupported threats. To that end, we support the approach that the
SDT appears to be taking of modifying a limited number of applicable standards so
that they apply to GO/GOP lead lines. In particular, we fully support the fact that the
SDT recognizes that GO/GOPs should not automatically be required to register as
TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case
determination. As already noted, registering a GO/GOP as a TO/TOP may actually
decrease reliability.
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Question 7 Comment
Response: Thank you for your comment and support.
RES Americas Development
Yes
We believe that the standards modifications proposed by the SDT should address any
genuine reliability gap with regard to generator lead lines, rather than just perceived
but unsupported threats. To that end, we support the approach that the SDT appears
to be taking of modifying a limited number of applicable standards so that they apply
to GO/GOP lead lines. In particular, we fully support the fact that the SDT recognizes
that GO/GOPs should not automatically be required to register as TO/TOPs simply
because of their ownership of generator lead lines. The SDT correctly recognizes that
such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Response: Thank you for your comment and support.
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Yes
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Question 7 Comment
Standards Collaborators
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Xcel Energy
Yes
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Organization
Yes or No
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 7 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
South Carolina Electric and
Gas
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
Tennessee Valley Authority
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8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the appropriate ones?
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, commenters either offered their support or directed
the SDT to their comments on other questions in this report.
Organization
Yes or No
Ameren
No
Question 8 Comment
Please refre to our comments in reposnes to #3, #4, and #5 above.
Response: Please see the SDT’s responses to Questions 3, 4, and 5.
Texas Reliability Entity
No
See comment 6.
Response: Please see the SDT’s response to Question 6.
Ingleside Cogeneration LP
(Occidental Chemical)
No
See comments to questions 1 through 4.
Response: Please see the SDT’s responses to Questions 1-4.
SERC Planning Standards
Subcommittee
No
See our comments above for question # 3.
Response: Please see the SDT’s response to Question 3.
South Carolina Electric and
Gas
No
The modifications are appropriate with the exception noted in question #3.
Response: Please see the SDT’s response to Question 3.
ACES Power Marketing
No
The modifications are largely the appropriate ones with the exceptions we noted in Q1
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Organization
Yes or No
Standards Collaborators
Question 8 Comment
and Q10.
Response: Please see the SDT’s responses to Questions 1 and 10.
Southwest Power Pool
Standards Development Team
No
We agree that the standards being addressed are correct. See above comments.
There are some issues with the determination of which facilities are deemed BES since
ownership of what may be a BES facility may not always be by a Transmission Owner.
All relevant standards should apply to BES facilities regardless of ownership.
Response: Thank you for your comment.
PSEG
No
Response:
SERC OC Standards Review
Group
See comments on Question 7. If the standards referenced in question 7 are FAC-001,
FAC-003 and PRC-004, we would answer yes to this question.
Response: Thank you for your comment and support.
Southern Company
Yes
 The version history table is incorrect - change version 3 to version 2.1.  
Response: Thank you for your comment. We have made this change.
RES Americas Development/
American Wind Energy
Association
Yes
For the most, we agree that the SDT proposal strikes a reasonable balance and
provides the requisite level of clarity and certainty necessary for GO/GOPs to
understand their responsibilities and compliance requirements.
Response: Thank you for your comment and support.
MRO NSRF
Yes
The NSRF agrees if the drafting team incorporates as suggested improvements
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Organization
Yes or No
Question 8 Comment
Response: Thank you for your comment and support.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Yes
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Organization
Yes or No
Question 8 Comment
Company
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
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9. If you answered “no” to Question 7, what standards need to be added or removed to achieve the SDT’s goal? Please provide
technical justification for your answer.
Summary Consideration:
The SDT thanks all stakeholders who submitted comments. Few stakeholders suggested that standards need to be added
or removed to achieve the SDT’s goal.
One commenter pointed out that PRC-005-1a required the same kind of change made in the proposed PRC-004-2.1a to
ensure that generator interconnection Facility Protection Systems are included within that standard. The SDT agrees with
this suggestion and has initiated a process to modify R1 and R2 in PRC-005-1a.
A few commenters returned to FAC-001-1 and stated their concern about the feasibility of adding FAC-001-1 to the
applicability section of this standard. The SDT agrees with commenters that the issues surrounding the interconnection of
a third party Facility to a GO’s existing Facilities are complex ones, and reminded commenters that it did its best to
address these complexities in the resource document titled “Technical Justification: FAC-001-1.” The SDT also points out
that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or indirectly
with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro
forma interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any
studies with an affected system which could include Facilities owned by one, or more, TO on the other side of the GO’s
existing point of interconnection. The SDT acknowledges that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
Some commenters suggested that the SDT reexamine the standards cited in the Milford and Cedar Creek FERC orders.
The SDT continues to find clear and technical reliability-based reasons that support not adding GO and GOP requirements
to these standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern,
the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 9 Comment
Cowlitz County PUD
No
N/A
Manitoba Hydro
No
See question 7 comments.
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Organization
Yes or No
Question 9 Comment
Response: See the SDT’s response to Question 7.
Southern Company
Yes
Southern does not think that the revision to FAC-001-1 is necessary. A Generator
Owner (GO) cannot assess reliability impacts to the Bulk Electric System (BES) and
determine acceptability without support and involvement of the applicable owner and
operator of the Transmission System (i.e., the “interconnected TO” or “interconnected
TP”). A generator tie-line does not equate to a Transmission System. A GO must
already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties’ facilities to its own interconnection
Facilities. Stated another way, the GO does not need Facility Connection
requirements to govern how multiple units are tied to a collector bus so why are they
needed for a third party to connect to an existing tie-line? In either case it is the
interconnected TO or interconnected TP that has connection requirements that must
be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its
interconnected TO or interconnected TP. A GO should not need to develop
“connection requirements” unless it is in the business of owning and operating
facilities independently of its interconnected TO or interconnected TP. We do not
believe a reliability gap exists in FAC-001-1 because the requestor for interconnecting
another Facility to an existing generation Facility must coordinate with the applicable
TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable facility
connection and performance requirements. If and when there is an agreement in
place for a third party to connect to a generator tie-line then the tie-line would
become part of the integrated system and its purpose and the owner’s function would
likely warrant registration as a TO/TOP and FAC-001 would then apply. The following
excerpt from the 2010-07 Background Resource White Paper acknowledges that this
may be necessary: “The drafting team also acknowledges that, if another party
interconnects to a Facility owned by a Generator Owner, there may be the need to
address MOD or TPL standards. However, the drafting team believes that this, too, is
best handled through specific evaluation, perhaps accompanied by changes to the
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Organization
Yes or No
Question 9 Comment
compliance registry. Entities that face this kind of scenario may also meet criteria
applicable to other registrations such as Transmission Service Provider or Transmission
Planner.” [Arguments related to jurisdictional, interconnection policy and open access
transmission tariff issues](1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access
transmission tariff (OATT), a GO should not be required to comply with FAC-001-1
until that GO’s generating Facility reaches commercial operation. NERC should not
make facilities subject to the mandatory reliability standards before the facilities are
actually part of the BES.(a) Jurisdiction under FPA Section 215. First, it is not clear
that NERC or FERC has jurisdiction under FPA Section 215 to require generation
facilities that have not actually reached commercial operation to be subject to
reliability standards. Section 215(a)(2) of the FPA defines the “Electric Reliability
Organization” as “the organization certified by the Commission ... the purpose of
which is to establish and enforce reliability standards for the bulk-power system,
subject to Commission review.” Further, (a)(3) provides that “The term ‘reliability
standard’ means a requirement, approved by the Commission under this section, to
provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide
for reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design
of planned additions or modifications. It is logical to interpret the phrase “design of
new facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted
as requiring that a generating facility that has not yet reached commercial operation
should be subject to reliability standards (including audit and penalties). Therefore,
the GO with the existing generation facilities should not be required to incorporate
the proposed generation facility into its Facility connection requirements before the
proposed generation facility is subject to NERC or FERC jurisdiction. (b) FERC’s
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Question 9 Comment
interconnection policy. In addition, the revised FAC-001 would appear to place
restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC
was very concerned about the ability of interconnection customers to interconnect
their generating facilities and gave them a fair amount of flexibility. However, this
revised FAC-001 would appear to restrict some of this flexibility.(i) Order No. 2003
gives the interconnection customer the ability to terminate a proposed
interconnection on ninety days notice. Therefore, the interconnection customer is not
required to build the facility. However, this revised FAC-001 appears to assume that
the interconnection customer does not have this flexibility. What if the
interconnection customer (the GO building a new generator on its site or the third
party building a new generation facility) decides to terminate the Large Generator
Interconnection Agreement (LGIA) or not proceed with the generation facility? In such
event, the GO may be required to revert to its previous Facility connection
requirements in order to accommodate the original configuration. (ii) The LGIA
permits modifications to the proposed interconnection. How would this affect the
Facility connection requirements? How long would the GO have to revise its Facility
connection requirements? In the event that there is a single modification, or perhaps
multiple modifications, how does the GO stay in compliance with this standard? (iii)
FAC-001-1, R4 provides that each GO with Facility connection requirements and each
TO shall maintain Facility connection requirements and make documentation of these
requirements available to users of the Transmission System upon request. However,
Large Generator Interconnection Procedures (LGIP), Section 3.4 requires the posting
of certain interconnection information but the identity of the interconnection
customer is not to be disclosed (unless it is an Affiliate). Requirement R4 would
appear to potentially require disclosure of information and (more importantly) of the
interconnection customer's identity in contravention of the requirements in Order No.
2003 and the LGIP.(c) OATT requirements. The definition of “applicable Generator
Owner” (Section 4.2.1) and Requirement R2 provide that the GO will have an executed
Agreement to evaluate the impact of interconnecting a new facility to the GO’s
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Question 9 Comment
existing generation facility. This statement is ambiguous. This statement could be
understood to mean that the GO of the existing generation Facility will enter into an
Agreement with the GO proposing to interconnect and the existing GO will evaluate
the impact of the proposed interconnection. However, requests to interconnect new
generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the
new facility. Thus, the language in FAC-001-1 would need to be revised to clarify that
the owner of the new facility will need to interconnect under the OATT of an
appropriate Transmission Provider (i.e., the Transmission Provider to which the
existing GO is interconnected, not with the existing GO). Therefore, the owner of the
new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be
developing a merchant transmission line. In that case, the existing GO would need to
evaluate whether it needs have its own OATT and OASIS. In that case, the new
generator owner would be interconnecting to the existing GO. However, the existing
GO’s line would not be a generator tie-line. This issue is not clear from the draft
standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES
reliability...” (b) It is unclear in Applicability section 4.2.1 that the term “Agreement”
means that the GO has an executed agreement with a TO/TSP or that the GO and the
third party have an executed agreement. Without further explanation, the capitalized
term “Agreement” has the effect of introducing confusion. If the SDT does not intend
to propose a new addition to the NERC Glossary of Terms, it should use the lower case
term, “agreement.” With respect to the capitalized term, “Transmission System,” the
SDT should consider clarifying if it intends to propose adding this to the Glossary. (3)
Effect of the proposed revisions to FAC-001-1 on FAC-002-1.(a) As drafted, there are
scenarios under which a new GO may attempt to interconnect to an existing GO even
though, as explained above, the interconnection should actually be done to the
appropriate Transmission Provider. If the appropriate Transmission Provider is not
included in the evaluation of the interconnection various types of harm may occur. In
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Organization
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Question 9 Comment
such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002. (b) FAC-001 and FAC-002 should
be revised to be clear that the existing GO and any new GOs must coordinate any
interconnection with the appropriate Transmission Provider, TP and PA.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as appropriate.
PSEG
Yes
We believe that the Ad Hoc Group’s suggestions regarding PRC-005-1 - Transmission
and Generation Protection System Maintenance were correct and that this standard
should have been modified by the SDT in a manner similar to the way the SDT
modified PRC-004-2. This would require modifying R1 and R2 in PRC-005-1a (the
current version) to include protection systems in the generator interconnection
Facility. In addition, the SDT should evaluate modifying PER-002-0 - Operation
Personnel Training. In doing so the SDT completes one of the open FERC directives in
Order 693. Paragraph 1363 addresses GOP training:1363. Further, the Commission
agrees with MidAmerican, SDG&E and others that the experience and knowledge
required by transmission operators about Bulk-Power System operations goes well
beyond what is needed by generation operators; therefore, training for generator
operators need not be as extensive as that required for transmission operators.
Accordingly, the training requirements developed by the ERO should be tailored in
their scope, content and duration so as to be appropriate to generation operations
personnel and the objective of promoting system reliability. Thus, in addition to
modifying the Reliability Standard to identify generator operators as applicable
entities, we direct the ERO to develop specific Requirements addressing the scope,
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Organization
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Question 9 Comment
content and duration appropriate for generator operator personnel.
Response: Thank you for your comment. The SDT agrees with the comment concerning PRC-005-1a and will be initiating a process to
make that change.
With respect to PER-002-0, the SDT continues to find that there are no clear and technical reliability reasons that support adding GOP
requirements to any PER standard based on the fact that the GOP operates a generator interconnection Facility. While the SDT does
not necessarily disagree that some training requirements for GOPs may be necessary, it does not see how these changes fall within its
scope.
Ingleside Cogeneration LP
(Occidental Chemical)
Ingleside Cogeneration LP believes that the set of standards proposed by the SDT is
technologically accurate and defensible. The open issue is if the ERO and FERC expect
more standards to be included - whether based upon sound reliability principals or
not.
Response: Thank you for your comment and support.
Western Electricity
Coordinating Council
PLease see response to question #7.
Response: See the SDT’s response to Question 7.
Texas Reliability Entity
See comment 6.
Response: See the SDT’s response to Question 6.
SERC OC Standards Review
Group
See comments on Questions 7 & 8.
Response: See the SDT’s responses to Questions 7 and 8.
Florida Municipal Power
see response to Question 7
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Question 9 Comment
Agency
Response: See the SDT’s response to Questions 7.
Manitoba Hydro
The revision to FAC-001-1 R2 may be problematic, depending on what was intended.
Under the revised requirement, the obligation to comply is dependent on the
execution of an agreement to evaluate reliability impacts under FAC-002-1. However,
FAC-002-1 does not clearly require the execution of an agreement by the Generator
Owner. FAC-002-1 only requires the Generator Owner to “coordinate and cooperate
on its assessments with its Transmission Planner and Planning Authority”. Accordingly
if a Generator Owner coordinates without executing an agreement to perform an
assessment, compliance with FAC-001 R1 will not be required.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Southwest Power Pool
Regional Entity
The SDT should consider the standards that FERC identified in 135 FERC ¶ 61,241.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives). However, based on your and other comments, we have expanded our technical
justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
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10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, many stakeholders offered supportive comments.
Others offered a variety of suggestions, many of which were addressed.
One commenter suggested that the word “system” should not be capitalized in “Transmission System” in FAC-001-1
because the NERC glossary term “System” does not apply within the standard. The SDT agreed with this suggestion, and
changed all references to “Transmission System” to “interconnected Transmission systems” for consistency in other parts
of the standard and with FAC-002. Another commenter pointed out that “within” should be “with” in Section 4.2.1, and
the SDT made this change.
A few commenters repeated their concern with the exclusion in FAC-003 for GOs with specific kinds of interconnection
Facilities. For these commenters, the SDT reemphasized that in many cases, generation Facilities are either (1) staffed and
the overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have
generally supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
Some stakeholders offered comments that were outside the scope of this SDT’s work. A few offered comments on the
overall strategy of the FAC-003-2 standard, and the SDT informed them that these comments should have been
submitted when the Project 2007-7 Vegetation Management posted its work for comment.
One commenter suggested changes to the VSLs for R1 and R4. Because the SDT made no changes to these requirements,
modifying the VSLs for these requirements is outside the scope of this team. This item will be added to the issues
database.
Several stakeholders suggested the SDT review the standards cited in the draft NERC directive regarding generator
interconnection leads and in the FERC orders regarding Milford and Cedar Creek. The SDT continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these standards and not
requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern, the SDT has expanded its
technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
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Organization
Yes or No
Question 10 Comment
Gainesville Regional Utilities
Negative
1. It would seem that the impetus for FAC003 is to eliminate vegetation related
outages within the rights-of-way as defined and subject to the exclusions as stated in
footnote
2. Thus the requirement is to manage the ROW to prevent vegetation related
sustained outages with the measure being no outages. With grow-ins and fall-ins from
within the defined ROW being controllable factors. 2. Including encroachments leaves
the door open for fines to be imposed with no actual outage(s) having occurred. This
may be like being found guilty of a crime that has not yet taken place.
3. Combine vegetation related sustained outages by “grow-ins” and “blowing
together of lines and vegetation located inside the ROW” as one item as they are both
consequences of the growth of vegetation either vertically and horizontally.
4. Leave vegetation related sustained outages by “fall-in” as a standalone as this will
be related to structural problems occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and implementation of a Transmission
Vegetation Management Plan which shall include documented maintenance
strategies or procedures or processes or specifications, delineation of an annual work
plan and completion of same). Thus this would be the competency based
requirements as a program without execution is meaningless.
6. R1 and R2 become R2 and R3.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and found that a response to this comment was provided. No change made.
Northern Indiana Public
Service Co.
Negative
Ballot needs work
Response: The SDT does not understand your specific concern.
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Organization
Yes or No
PSEG Energy Resources &
Trade LLC, PSEG Fossil LLC,
Public Service Electric and Gas
Co.
Negative
Question 10 Comment
FAC-003-X is not applicable since FAC-003-2 was approved by the BOT on November
4, 2011
Response: Thank you for your comment. You are correct that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 –
Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Hydro-Quebec TransEnergie
Negative
Hydro-Quebec TransEnergie is casting a negative vote again because our comment
from the last posting was not considered in the current draft: The minimum
frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of 50 degrees
North, the vegetation growth rates is limited. The Vegetation Inspection frequency in
the territories located above 50 degrees of latitude must be relaxed to 3 years.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and did not find this comment had been submitted as part of that project effort. No
changes made.
New Brunswick System
Negative
Since NBSO voted 'affirmative' for FAC-003-3, it makes sense for us to vote 'negative'
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Operator
Question 10 Comment
for this standard.
Response: Thank you for your comment. In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with
the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually
only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved
by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation
on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
PSEG Energy Resources &
Trade LLC/ Public Service
Electric and Gas Co./ PSEG
Fossil LLC
Negative
The phrase “generator Facility” should be “generator Transmission Facility,” and the
phrase “Transmission System” should be “Transmission system.”
Response: Thank you for your comment. We agree with your change to “Transmission system” but not to the addition of
“Transmission” in the phrase “generator Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part
because in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC. Therefore, the SDT
intentionally modified language so that a Facility owned by a generation entity did not contain the term “Transmission.”
SERC Reliability Corporation
Negative
There should not be a weak link under the standard. This proposed revision would
create a weak-link where a portion of the otherwise covered right-of-way would be
exposed.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
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Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
New York State Department
of Public Service/ National
Association of Regulatory
Utility Commissioners
Negative
Understand that there is an open issue regarding the availablility of generation
compliance documentation that needs to be satisfactorily addressed.
Response: The SDT does not understand your specific concern.
Infigen Energy US
Affirmative
Infigen supports the efforts of the SDT to ensure that Protection System
Misoperations affecting the reliability of the BES are thoroughly analyzed and
mitigated. Generator Owners are already analyzing Misoperations as/if they occur,
and are employing Corrective Action Plans to avoid future Misoperations. We support
maintaining "reasonable and appropriate" preventative measures and risk assessment
tools to ensure that misoperations are evaluated and corrected expediently.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC/PPL NERC
Registered Affiliates
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
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requirements throughout other NERC standards.
Response: Thank you for your comment and support.
SERC Reliability Corporation
Affirmative
The Generator Owner may be required to self-certify and report periodically to the
region whether they have become applicable to the standard.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc./ ACES Power
Marketing Standards
Collaborators/ ACES Power
Marketing
Affirmative
The modifications to PRC-004-2.1 R2 could be interpreted as requiring the GO to
analyze Protection System Misoperations on the generator interconnection Facility
even if it does not own the Facility. We suggest modifying the requirement as shown
below to address this issue.”The Generator Owner shall analyze Protection System
Misoperations on its generator and generator interconnection Facility that it owns ...”
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
SERC Reliability Corporation
Affirmative
With the understanding the Generator Interconnection FAcilities will be grouped with
Transmission Protection Systems for analysis at the regional level.
Response: Thank you for your comment and support.
Entergy Services
We suggest that the Vegetation Management Standards should be consistent for
both the TO and GO facilities. We would also like to suggest an additional
Recommendation for added clarity regarding Category 3 Outages (Off-ROW Fall-in
Outages). We understand that the Category 3 Outages are not a violation of the
Standard, but we feel that there should be some level of comment added within the
Standard clearly stating that these Outages are “Reportable Only” during the
Quarterly Outage reports to the RE’s, and that there are no associated
violations/sanctions for this Category Of Outage, and that an Off-ROW fall-in outage
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would not be considered an encroachment into the MVCD in any way. The Technical
Reference Document does a good job of clearly stating this in the Introduction on
Page 5 (“This standard is not intended to address outages such as those due to
vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human
activities or acts of nature.”) and we feel that this should also be stated clearly in the
Standard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight.
The remainder of your comment is outside the scope of this SDT.
Southern Company
We agree with the 2010-17 Standard Drafting Team’s conclusion to not modify other
standards such as those mentioned on page 4 of the Technical Justification document.
In additon, we wish to provide the following support for exclusion of these specific
standards. Southern Company believes NERC’s Project 2010-07 SDT must challenge
making revisions to the standards included in the FERC order on Cedar Creek and
Milford. (This order supports NERC’s requirement for those entities to register as a
TO/TOP due to their ownership of generator interconnection circuits > 100kV.) We
believe there are clear technical and reliability-based reasons that support not adding
GO and GOP requirements to these standards and not requiring the GO or GOP to
register as a TO or TOP. Furthermore, we also believe there are clear distinctions
between GO/GOP responsibilities and TO/TOP responsibilities that must be
maintained to ensure BES reliability. Revising standards to assign TO/TOP
responsibilities to a GO/GOP or requiring a GO/GOP to register as a TO/TOP because
of generator interconnection circuits > 100kV will reduce the clarity of these
responsibilities. We have provided specific comments on each standard below:
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EOP-005-1 R1, R2, R6, R7R1 and R2 require each TOP to have and maintain a system
restoration plan. R6 requires the TOP to train its operating personnel in
implementing this plan. R7 requires the TOP to verify its restoration plan by actual
testing or simulation. These requirements are clearly the role and responsibility of
the TOP, not a GO/GOP who happens to have generator interconnection facilities in
the TOP’s control area. The GOP’s roles and responsibilities are clearly and
appropriately addressed EOP-005-2. The presence of a generator interconnection
circuit > 100kV that happens to be owned by the GO instead of the TOP
fundamentally does not change the roles and responsibilities of the TOP or the GOP.
Thus, no changes due to EOP-005 are needed.
FAC-014-2, R2: FAC-014-2 R2 states “The Transmission Operator shall establish SOLs
(as directed by its Reliability Coordinator) for its portion of the Reliability Coordinator
Area that are consistent with its Reliability Coordinator’s SOL Methodology.” FAC014-2 R2 should not be revised to include GOPs. The GO is required by FAC-008-1 R1
and FAC-009-1 (FERC approved version) and pending FAC-008-3 R3 and R6 (FAC-008-3
filed with FERC for approval) to document the Facility Ratings for a GO-owned
generator interconnection circuit >100kV. The established Facility Rating must
respect the most limiting applicable equipment rating in the circuit and must consider
operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the GO to
the GOP if they are not the same entity. The operating voltage limits for this circuit
are established by the applicable TO/TOP, not the GO or GOP. Therefore, we believe
adding the GO to FAC-014-2 R2 would be redundant.
PER-003-1 R2, R2.1, R2.2PER-003-1 R2 and its sub-requirements state:”R2. Each
Transmission Operator shall staff its Real-time operating positions performing
Transmission Operator reliability-related tasks with System Operators who have
demonstrated minimum competency in the areas listed by obtaining and maintaining
one of the following valid NERC certificates (1 ) : [Risk Factor: High][Time Horizon:
Real-time Operations]: R2.1. Areas of Competency R2.1.1. Transmission operations
R2.1.2. Emergency preparedness and operations R2.1.3. System operations R2.1.4.
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Protection and control R2.1.5. Voltage and reactive R2.2. Certificates o Reliability
Operator o Balancing, Interchange and Transmission Operator o Transmission
Operator This requirement is specifically for TOPs. Personnel training for GOPs needs
to be addressed separately and not mingled with responsibilities of the TOP. The
GOPs role in supporting BES reliability needs to be clearly understood and defined
prior to establishing training requirements in the standards.
PRC-001-1, R2, R2.2, R4, R6Generator Operators (GOPs) and the scope of protection
equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirement R2 and sub-requirement R2.2 The
language used in requirement R2 which applies to the GOP uses the general terms
“relay or equipment failures” which would include not only generator relaying, but
generator interconnection relaying in the GOPs scope as well. The GOP is required to
notify the TOP and Host BA in R2.1 “if a protective relay or equipment failure reduces
system reliability.” Requirement R2.2 requires the affected TOP to notify its RC and
affected TOPs and BAs. Thus, applying R2.2 to a GOP would be redundant to R2.1.
Requirement R4 states, “Each Transmission Operator shall coordinate protection
systems on major transmission lines and interconnections with neighboring
Generator Operators, Transmission Operators, and Balancing Authorities.” A
generator interconnection tie line does not constitute a ‘major tie line” or major
“interconnection with neighboring GOPs, TOPs, and BAs.” Thus, R4 should not be
revised to include GOPs. If a GO exists within NERC that does own such
interconnection facilities, the responsibility for coordination of protection systems on
such a line or interconnection should be the responsibility of the TOP in that area, not
the GO/GOP. This may require formal agreements between the TO/TOP and GO/GOP,
since the GO may own protection equipment on his end. The same logic applies to
R6. R6 states, “Each Transmission Operator and Balancing Authority shall monitor the
status of each Special Protection System in their area, and shall notify affected
Transmission Operators and Balancing Authorities of each change in status.” This is
clearly the responsibility of the TOP and/or BA, not a GO/GOP who happens to have
generator interconnection facilities in the area. An SPS function by definition is to
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maintain BES reliability. If a GO/GOP has equipment within the equipment scope of a
Special Protection System (SPS), responsibility for monitoring the SPS should be
conveyed in a formal agreement as appropriate.
TOP-001-1 R1Requirement R1 states, “Each Transmission Operator shall have the
responsibility and clear decision-making authority to take whatever actions are
needed to ensure the reliability of its area and shall exercise specific authority to
alleviate operating emergencies.” This is clearly the responsibility of the TOP, not a
GO/GOP who happens to have generator interconnection facilities in the TOP’s area.
Thus, R1 should not be applied to a GO/GOP who owns or operates generator
interconnection facilities. Furthermore, TOP-001-1 R3 (proposed to be covered in the
future in the proposed IRO-001-2 R2 and R3) appropriately requires the GOP to
comply with reliability directives issued by the TO “unless such actions would violate
safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the TOP the necessary decision-making authority over operation of all
generator Facilities up to the point of interconnection. They also give the GOP the
necessary authority to take appropriate actions to ensure safety and protection of the
GO’s equipment. Thus, no changes to TOP-001-1 are necessary.
TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4Requirement R6 and its sub-requirements state:
“R6. Transmission Operators, individually and jointly with other Transmission
Operators, shall develop, maintain, and implement formal policies and procedures to
provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional
reliability, including:R6.1. Monitoring and controlling voltage levels and real and
reactive power flows.R6.2. Switching transmission elements.R6.3. Planned outages of
transmission elements.R6.4. Responding to IROL and SOL violations.”These are clearly
the responsibility of the TOP, not a GO/GOP who happens to have generator
interconnection facilities in the TOP’s area. Thus, these requirements should not be
applied to a GO/GOP who owns or operates generator interconnection facilities. The
same logic applies here as stated above in our discussion on TOP-001-1. We believe it
is inappropriate and would be adverse to BES reliability to apply these requirements
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to a GOP. TOP-004-2 effectively gives the TOP the necessary decision-making
authority over operation of all generator Facilities up to the point of interconnection.
They also give the GOP the necessary authority to take appropriate actions to ensure
safety and protection of the GO’s equipment, such as opening high voltage generator
output breakers when required to protect the unit. Thus, no changes to TOP-004-2
are necessary.TOP-006-2 R3Requirement R3 states, “R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall provide appropriate technical
information concerning protective relays to their operating personnel. The intent of
this requirement when applied to a GOP is already addressed in PRC-001-1 R1 which
states, “Each Transmission Operator, Balancing Authority, and Generator Operator
shall be familiar with the purpose and limitations of protection system schemes
applied in its area.” Thus, no change to TOP-006-2 is necessary.   
Response: Thank you for your comment and support. We agree that there are clear and technical reliability-based reasons that
support not adding GO and GOP requirements to these standards and not requiring the GO or GOP to register as a TO or TOP. We
have expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement
cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and many of your explanations are
included therein.
American Wind Energy
Association
AWEA appreciates the opportunity to submit these comments on the NERC Project
2010-07. AWEA supports the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. AWEA supports the intent and goal of the SDT to ensure
that all generator-owned Facilities are appropriately covered under NERC’s Reliability
Standards. We also agree with the SDT that while many GO/GOPs operate Elements
and Facilities that might be considered by some entities to be Transmission, these are
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most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore,
we support the SDT’s approach of identifying a very limited number of TO/TOP
standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP owners
of generator lead lines. We would be concerned, however, if additional requirements
were added beyond FAC-001, FAC-003, and PRC-004. Consideration of any additional
standards with respect to generator lead lines should be done on a standard-bystandard basis, reviewing the applicability of each standard as well as the impact on
the reliability of the Bulk Electric System.
Response: Thank you for your comment and support.
Bonneville Power
Administration
BPA thanks you for the opportunity to comment on Project 2010-07, Generator
Requirements at the Transmission Interface. BPA stands in support of the proposed
revisions and has no comments or concerns at this time.
Response: Thank you for your comment and support.
Constellation Power Source
Generation
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. While the revision process focuses on specific standards, it is
important to consider the reliability questions in the context of the full complement
of reliability standards that apply to entities. For instance, the following standards
already apply to generators and relate to the reliability considerations around
transmission at the generator interface:
o PRC-001-1 addresses coordination of protection system components by requiring all
GOs to ensure coordination of their protection system with interconnected parties.
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Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA, etc.
o PRC-004-1 requires all GOs to ensure that they analyze all misoperations on their
protection system which would include the protection of the tie line.
o TOP standards applicable to GOs aid coordination between a GO and a TO with
regards to the generator tie line by requiring all GOs to coordinate all maintenance
and emergency outages (both forced and planned) with all applicable interconnected
parties. Further, all ISO procedures require the same of GOs.
o RC, TOP and/or BA certified operators control and are responsible for overseeing
that transmission. According to the NERC functional model, a Generator Operator is
defined as “operat(ing) generating unit(s) and perform(ing) the functions of supplying
energy and reliability related services.” Given this limited scope, the Generator
Operator (GOP) cannot be considered as operating on the same level as the Reliability
Coordinator, Transmission Operator or Balancing Authority when it comes to real
time information on the status of the BES. The GOP does not monitor and control the
BES, rather the GOP only monitors and controls the generators that it operates and
relays information to other operating entities.
o IRO and TOP standards applicable to GOs include tie lines in their pool of resources
to alleviate operational emergencies by requiring all GOs to operate as directed by
their TOP, BA, or RC as directed and must render emergency assistance.
o FAC-8 and FAC-9 manage rating methodology consistency by requiring all GOs to
develop a methodology to rate all equipment, and that the RC has the authority to
challenge the GO on that methodology. The onus is on the GO to either change their
methodology and rating accordingly, or provide a technical justification as to why
they cannot adopt the changes. Further, a generator will never be limited by its tie
line, as a generator’s profits are directly tied to its output. Therefore no generator
would limit its facility to the equipment that is delivering that output.
Response: Thank you for your comment and support. We agree that it is important to consider the reliability questions in the context
of the full complement of reliability standards, and we have endeavored to make these broader connections clear in our revised
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technical justification document (posted under “Supporting Materials”). That document has been expanded to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and the kinds of further
justifications you also provided are included therein. After another thorough review of these standards, the SDT continues to believe
that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
Cowlitz County PUD
In answer to the SDT request for feedback on FERC's Order concerning Cedar Creek
and Milford, the District finds no technical reason to add any of the listed standard
requirements, and struggles to understand why FERC would even consider this listing
as applicable.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc.
In section 4.2.1 of the Applicability Section, “within” should be “with”. Because
NERC’s Glossary of Terms establishes that an Agreement can be verbal and not
enforceable by law, section 4.2.1 should be further modified to clarify that it is a
legally enforceable and fully executed Agreement. The language in R3 in parenthesis
after Generation Owner should be modified to “once required by Requirement R2”.
This makes it clearer that R3 does not apply until the GO has an executed Agreement
to evaluate a request by a third part to interconnect.
Response: Thank you for your comment. We agree that “within” should be “with.” The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Manitoba Hydro
Manitoba Hydro would also like to point out that if the redline changes are
implemented, it will greatly increase the complexity of coordination required under
FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
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Compliance & Responsbility
Organization
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NextEra Energy, Inc. (NextEra) appreciates the work of the Project 2010-07 Generator
Requirements at the Transmission Interface Standard Drafting Team (SDT) on a
subject that NextEra has a significant interest in resolving. In fact, NextEra has been a
member of the SDT and an active observer. Given the recent events - such as (a) the
North American Electric Reliability Commission's draft interim directive; (b) the denial
of the Milford and Cedar Cheek requests for reconsideration at the Federal Energy
Regulatory Commission (FERC) and (c) the record in this case which, at times, suggests
the SDT needs to more formally consider the Milford and Cedar Cheek Reliability
Standards - NextEra requests that SDT more formally consider the merits of each
Reliability Standard adopted the Milford and Cedar Cheek FERC orders and the NERC
draft interim directive. Although NextEra does not condone the manner in which
NERC issued the interim draft directive and stated so in its comments to NERC on the
interim draft directive, NextEra’s overarching objective on this issue is to bring a
uniform, fair and technically supported approach that resolves the interface issue.
Thus, NextEra requests that the SDT (prior to proceeding any further or any additional
comments or votes on specific draft Reliability Standards) issue a technical paper that
point-by-point addresses the merits of including the Reliability Standards set forth in
the FERC Orders and NERC’s draft interim directive, and request stakeholder,
including NERC staff, comment. For example, this technical paper would likely the
merits of NERC’s draft interim directive not requiring NERC-certified operators (but
require training of interface operators), while FERC’s orders require NERC-certified
operators. While NextEra does not agree five days of training is necessary for an
interface operator, as the draft interim directive appears to propose, NextEra does
believe a technical case can be made why NERC-certification is not required, and that
some degree of training related to the applicable Reliability Standards is reasonable.
Similar, on FAC-003 (as well as several other Standards), the draft interim directive
proposes a slightly different approach than the SDT. NextEra would rather these
approaches reconciled than be in conflict, with the potential for continued conflict as
the SDT’s work product proceeds. Further, NextEra requests that the SDT’s review
the technical merits of NERC’s proposed criteria to determine what generator
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transmission lead is required to comply with additional Reliability Standards. As
noted, above, this technical paper should be posted for stakeholder, including NERC
staff, comment. Accordingly, while NextEra would have preferred that NERC and the
Regional Entities express there interim draft directive approach on the record in this
proceeding, NextEra believes it is appropriate for the SDT to draft a comprehensive
technical paper that, with an open approach, considers the inclusion of additional
Reliability Standards, if appropriate, as a way of building lasting support for its
approach.
Response: Thank you for your comment and support. We certainly agree that is important for NERC staff and the SDT to continue to
work together to try to develop a mutually agreed upon solution for dealing with this reliability gap, and to a certain extent, the SDT
has tried to provide the kind of technical paper you suggest in its modified technical justification document (posted under “Supporting
Materials”), which has been expanded to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by
NERC in its draft compliance directive. The SDT does not, at this point, plan to develop a technical paper that discusses the merits of
the standards introduced by FERC and NERC, because its current focus is on filing the FAC-001-1, FAC-003-3, and PRC-004-2.1a with
FERC. As it moves forward to a final solution, however, this kind of technical paper may prove useful. We appreciate the suggestion.
Dominion
No
Tennessee Valley Authority
No
Exelon
PRC-004 - suggest that the Standard state that responsibility for the analysis of
missoperations of protective equipment shall be the responsibility of the owner of the
protective equipment.
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
ReliabiltiyFirst
ReliabilityFist has found a number of editiorial erros for the FAC-001-1 VSLs. They
include the following:1. VSL R1 - should not reference sub-requirements, should
reference the sub-parts consistent with the requirement (i.e. Requirement R1, Part
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1.1, 1.2 or 1.3) 2. VSL for R3 - the VSL should referenced Requirement 3, Part 3.1.1
through 3.1.16 rather than what is currently stated (Requirement R3, Part 3.1.1
R3.1.6)
Response: Thank you for your comment. While we agree that the VSLs for R1 need to be updated, that change is outside the scope of
this SDT because our changes are limited to those that incorporate the GO into the applicability of the requirement; the team made
no changes to R1 as it only includes the TO. We have, however, made the suggested changes to the VSLs for R3.
RES Americas Development
RES and AWEA appreciates the opportunity to submit these comments on the NERC
Project 2010-07. We support the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. RES and AWEA supports the intent and goal of the SDT to
ensure that all generator-owned Facilities are appropriately covered under NERC’s
Reliability Standards. We also agree with the SDT that while many GO/GOPs operate
Elements and Facilities that might be considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as
such should not be subject to the same standards applicable to TO/TOPs, who own
and operate Transmission Elements and Facilities that are part of the integrated grid.
Therefore, we support the SDT’s approach of identifying a very limited number of
TO/TOP standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP
owners of generator lead lines. We would be concerned, however, if additional
requirements were added beyond FAC-001, FAC-003, and PRC-004. Consideration of
any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the
impact on the reliability of the Bulk Electric System.
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Sempra Generation
Question 10 Comment
Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
SERC Planning Standards
Subcommittee/ SERC OC
Standards Review Group
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”
Response: Thank you for your comment and support.
END OF REPORT
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On January 20, 2012, Exelon submitted a Level One Appeal of the standard process for FAC-003-3 and
FAC-003-X to NERC’s Vice President of Standards and Training that stated the following: “Exelon
believes that the NERC Standards Process Manual was not followed, and that based on the substantive
changes made to both Standards following the Initial Ballot, NERC should have set the Standards for
vote using a Successive Ballot rather than a Recirculation Ballot.”
NERC’s Vice President of Standards and Training submitted a timely response to the appeal that found
that “Exelon…made its case that the [Standard Processes Manual] was not adhered to and that a
change impacting applicability was made between the last successive and recirculation ballot.”
Accordingly, the Vice President of Standards and Training referred the issue to the Standards
Committee for handling, suggesting the following options:
1. Re-post the standard for a successive ballot and recirculation ballot. Essentially set the clock
back and correctly replay the last steps of the process.
2. Ask the SDT to remove the clarification language from the final standard and go directly to
recirculation ballot.
3. Ask the SDT to redesign the challenged portion of the proposed standard.
He recommended that the Standards Committee pursue option 2. In a Standards Committee Executive
Committee (SCEC) conference call on February 23, 2012, the SCEC directed NERC staff to void the FAC003-3 and FAC-003-X recirculation ballot results of December 2011 and “remand the work to the
drafting team with direction to take into account the issues raised in the Exelon appeal submitted in
response to the recirculation ballot previously conducted and either: modify the language added
following the initial ballot and then re-post the standard for a successive ballot, or remove the language
added following the initial ballot and go directly to recirculation ballot.”
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments
submitted in the first successive ballot between October 5 and November 18, 2011. The SDT continues
to believe that a reference to line of sight is clarifying.
With this line of sight reference, the SDT simply seeks to clarify the exception language based on the
intent that has been agreed upon by the stakeholder body. In its Consideration of Comments report
from the last formal comment period, which ended on July 17, 2011, the SDT explained “We believe
that the one mile length is a reasonable approximation of line of sight, and that using a fixed starting
point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion
on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference
here, the SDT believes it has clarified its original intent and appropriately considered all comments
submitted.
The SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station switchyard to the
point of interconnection with a Transmission Owner’s Facility or (2) does not have a clear line of
sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s Facility and are:
Operated at 200kV or higher; or operated below 200kV identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
Additionally, “Regional Entity” has been removed from the applicability section of FAC-003-X because it
is not a recognized Functional Entity.
The FAC-003-3 and FAC-003-X recirculation ballot results of December 2011 have been voided, and
both standards are being posted for a 30-day concurrent comment period and successive ballot to
allow stakeholders the opportunity to comment on these changes.
Members of the ballot pool should note that for this ballot, the SDT will be balloting both FAC-003-3
and FAC-003-X, but stakeholders should not vote as though they are choosing one or the other. The
SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X
ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
2
other words, stakeholders who support adding GOs to the applicability of FAC-003 should vote in the
affirmative for both FAC-003-3 and FAC-003-X.
The Exelon appeal and NERC response are posted on the 2010-07 project page.
Status of other standards that are part of Project 2010-07:
•
•
FAC-001-1 and PRC-004-2.1a were adopted by NERC’s Board of Trustees on February 9, 2012
PRC-005-1.1a is currently posted for a 45-day concurrent comment and initial ballot.
No standards modified under Project 2010-07 will be filed with regulatory authorities until the Board of
Trustees has acted on the complete package of four standards.
In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO exemption
in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and changed “RE” to
“Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements
at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either
(1) staffed and the overhead portion is within line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting these Facilities because
incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and appropriate risk prevention
approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead
transmission lines that extend greater than one mile (1.609 kilometers) beyond the fenced area of the
generating switchyard or do not have a clear line of sight from the switchyard fence to the point of
interconnection and are…”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has
been agreed upon by the stakeholder body. In its Consideration of Comments report from the last
formal comment period, which ended on July 17, 2011, the SDT explained “We believe that the one
mile length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the part
of a Generator Owner or an auditor.” With the addition of an explicit line of sight reference here, the
SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
3
Members of the ballot pool should note that for its recirculation ballot, the SDT will be balloting both
FAC-003-3 and FAC-003-X, but stakeholders should not vote as though they are choosing one or the
other. The SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved
by FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually.
In other words, stakeholders who support adding GOs to the applicability of FAC-003 should vote in
the affirmative for both FAC-003-3 and FAC-003-X.
While this summary has been updated to reflect the status of FAC-003-3 and FAC-003-X, the SDT’s
responses to stakeholder comments below have not changed, except as they relate to FAC-003-3 and
FAC-003-X.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
4
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and
removed the Generator Owner from R4. Do you support the proposed redline changes to FAC001-1? (Please refer to the posted FAC-001-1 technical justification document for more
information about the SDT’s rationale for its changes.) …. .............................................................. 12
2.
Do you support the one year compliance timeframe for Generator Owners as proposed in the
Implementation Plan for FAC-001-1? …. ........................................................................................... 29
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some
commenters found the half-mile length too short, others found it too long, and still others found
the choice among the starting points of the switchyard, generating station, or generating
substation to be confusing. The drafting team attempted to address all of these concerns with its
latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile
beyond the fenced area of the generating station switchyard…” We believe that the one mile
length is a reasonable approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and any discretion on the
part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this
qualifier for Generator Owners because there is a very low risk from vegetation within the line of
sight, and thus the formal steps in this standard are not necessary to ensure reliability of these
lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a
decision that will be made as Project 2007-07—Vegetation Management moves forward, do you
support the proposed redline changes to FAC-003-X and FAC-003-3? …. ....................................... 34
4.
Do you support compliance timeframe for Generator Owners as included and explained in the
Implementation Plans for FAC-003-X? …. ......................................................................................... 50
5.
In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of
different scenarios that could play out with respect to the filing and approvals of FAC-003-2 and
FAC-003-3. Do you support this approach? If there are other scenarios that the SDT needs to
account for, please suggest them here. …. ...................................................................................... 57
6.
In its technical justification document, the SDT reviews all standards that had been proposed for
substantive modification in the Ad Hoc Group’s original support and explains why, with the
exception of FAC-003, modifying them would not provide any reliability benefit. Do you support
these justifications? If you believe the SDT needs to add more information to its rationale for any
of these decisions, please include suggested language here. …. ..................................................... 63
7.
The SDT is attempting to modify a set of standards so that radial generator interconnection
Facilities are appropriately accounted for in NERC’s Reliability Standards, both to close reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
5
gaps and to prevent the unnecessary registration of GOs and GOPs at TOs and TOPs. Does the set
of standards currently posted achieve this goal? …. ......................................................................... 74
8.
If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the
appropriate ones? ….......................................................................................................................... 87
9.
If you answered “no” to Question 7, what standards need to be added or removed to achieve the
SDT’s goal? Please provide technical justification for your answer. …. ............................................ 91
10. Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 99
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
6
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Gerald Beckerle
SERC OC Standards Review Group
1.
Scott Brame
NCEMC
2.
Troy Willis
Georgia Transmission Corp. SERC 1
3.
Mike Hirst
Cogentrix
SERC 5
4.
Bob Dalrymple
TVA
SERC 1, 3, 5, 6
5.
Matt Carden
Southern Co.
SERC 1, 5
6.
Shardra Scott
Gulf Power Co.
SERC 3
7.
Kerry Sibley
Georgia Transmission Corp. SERC 1
8.
Andy Burch
EEI
SERC 5
9.
Shaun Anders
City of Springfield (CWLP)
SERC 1, 3
SERC 1, 3, 5
11. John Troha
SERC 10
2.
Group
Jonathan Hayes
X
Southwest Power Pool Standards
Development Team
Additional Member Additional Organization Region Segment Selection
3
X
SERC 1, 3, 4, 5
10. Melinda Montgomery Entergy
SERC Reliability Corp
2
X
4
5
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Jonathan Hayes
Southwest Power Pool
SPP
2
2.
Robert Rhodes
Southwest Power Pool
SPP
2
3.
Don Taylor
Westar
SPP
1, 3, 5, 6
4.
John Allen
City Utilities of Springfield
SPP
1, 4
5.
Sean Simpson
MCPBPU
SPP
1, 3, 5
6.
Louis Guidry
CLECO
SPP
1, 3, 5
7.
Mitch Williams
Western Farmers
SPP
1, 3, 5
8.
Valerie Pinnamonti
AEP
SPP
1, 3, 5
9.
Bud Averill
Grand River Dam Authority SPP
1, 3, 5
OGE
1, 3, 5
10. Terri Pyle
3.
Group
SPP
Guy Zito, Guy Zito
Additional Member
2
3
4
5
6
7
Northeast Power Coordinating Council,
Northeast Power Coordinating Council
Additional Organization
Region
Alan Adamson
New York State Reliability Council, LLC
NPCC, NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC, NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC, NPCC 1
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC, NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC, NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC, NPCC 2
9.
Chantel Haswell
NPCC, NPCC 10
FPL Group, Inc.
NPCC, NPCC 5
10. David Kiguel
Hydro One Networks Inc.
NPCC, NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC, NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC, NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC, NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC, NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC, NPCC 1
16. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC, NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC, NPCC 5
18. Saurabh Saksena
National Grid
NPCC, NPCC 1
19. Michael Schiavone
National Grid
NPCC, NPCC 1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
10
X
Segment Selection
1.
8
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
20. Wayne Sipperly
New York Power Authority
NPCC, NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC, NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC, NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC, NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC, NPCC 3
4.
Group
Emily Pennel
No additional members listed.
Southwest Power Pool Regional Entity
5.
MRO NSRF
Group
Will SMith
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Jodi Jenson
WAPA
MRO
1, 6
4.
Ken Goldsmith
ALTW
MRO
4
5.
Alice Ireland
XCEL/NSP
MRO
1, 3, 5, 6
6.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
7.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
8.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
9.
Scott Nickels
RPU
MRO
4
10. Terry Harbour
MEC
MRO
1, 3, 5, 6
11. Marie Knox
MISO
MRO
2
12. Lee Kittelson
OTP
MRO
1, 3, 4, 5
13. Scott Bos
MPW
MRO
1, 3, 5, 6
14. Tony Eddleman
NPPD
MRO
1, 3, 5
15. Mike Brytowski
GRE
MRO
1, 3, 5, 6
16. Richard Burt
MPC
MRO
1, 3, 5, 6
6.
Group
Charles W. Long
Additional Member
Additional Organization
SERC Planning Standards Subcommittee
X
X
Region Segment Selection
1. Pat Huntley
SERC
SERC
10
2. John Sullivan
Ameren Services Co.
SERC
1
3. Philip Kleckley
SC Electric & Gas Co.
SERC
1
4. Bob Jones
Southern Company Services SERC
1
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
5. Jason Adams
7.
TVA
Group
SERC
Frank Gaffney
2
3
4
5
6
1
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Greg Woessner
Kissimmee Utility Authority FRCC
3
3. Jim Howard
Lakeland Electric
FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
8.
Group
FRCC
Mike Garton
Additional Member
Dominion
Additional Organization
Region Segment Selection
1. Michael Gildea
Dominion Resources Services, Inc.
RFC
2. Connie Lowe
Dominion Resources Services, Inc.
NPCC 5, 6
3. Michael Crowley
Virginia Electric and Power Company RFC
9.
Group
Annette M. Bannon
Additional Member
Additional Organization
5, 6
1, 3
PPL NERC Registered Affiliates
Region Segment Selection
1. Brent Ingebrigston
LG&E and KU Services Co.
SERC
3
2. Don Lock
PPL Brunner Island, LLC
RFC
5
3.
PPL Martins Creek, LLC
RFC
5
4.
PPL Holtwood, LLC
RFC
5
5.
PPL Montour, LLC
RFC
5
6.
Lower Mount Bethel Energy, LLC RFC
5
7. Annete Bannon
PPL Susquehanna, LLC
5
8. Leland McMillan
PPL Montana, LLC
10.
Group
Jason Marshall
Additional Member
Additional Organization
RFC
WECC 5
ACES Power Marketing Standards
Collaborators
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power
RFC
2. Erin Woods
East Kentucky Power Cooperative SERC
1, 3, 5, 6
3. Michael Brytowski
Great River Energy
1, 3, 5, 6
MRO
3, 5, 6
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
10
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11.
2
3
4
5
6
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
12.
Jack Cashin
Electric Power Supply Association
X
X
Individual
14. Individual
Natalie McIntire
Tom Flynn
American Wind Energy Association
Puget Sound Energy, Inc.
X
X
X
15.
Individual
Silvia Parada Mitchell
Compliance & Responsbility Organization
16.
Individual
Southern Company
Individual
Antonio Grayson
Chris Higgins/Stephen
Enyeart/Chuck
Mathews/Charles
Sheppard
18.
Individual
Thad Ness
American Electric Power
19.
Individual
BP Wind Energy North America Inc.
Individual
Carla Bayer
John Bee on behalf of
Exelon
Individual
Dennis Sismaet
Individual
Michelle D'Antuono
Seattle City Light
Ingleside Cogeneration LP (Occidental
Chemical)
23.
Individual
Michael Falvo
Independent Electricity System Operator
24.
Individual
Greg Rowland
Duke Energy
X
25.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
26.
Individual
Kirit Shah
Ameren
27.
Individual
John Seelke
Individual
29. Individual
30.
31.
Individual
13.
17.
20.
21.
22.
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Bonneville Power Administration
X
X
X
Exelon
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PSEG
X
X
X
X
Andrew Z. Pusztai
RoLynda Shumpert
American Transmission Company
South Carolina Electric and Gas
X
X
X
X
Individual
Ravi Bantu
RES Americas Development
Individual
Katy Wilson
Sempra Generation
28.
7
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
11
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Joe Petaski
Manitoba Hydro
X
X
X
X
Individual
34. Individual
Chris de Graffenried
Ed Davis
Consolidated Edison Co. of NY, Inc.
Entergy Services
X
X
X
X
X
X
X
X
35.
Individual
Alice Ireland
Xcel Energy
X
Individual
Russell A. Noble
Cowlitz County PUD
X
X
X
36.
X
X
37.
Individual
Anthony Jablonski
ReliabiltiyFirst
X
38.
Individual
Donald Jones
Texas Reliability Entity
X
39.
Individual
Amir Hammad
Constellation Power Source Generation
40.
Individual
Dennis Chastain
Tennessee Valley Authority
32.
Individual
33.
X
X
X
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
X
X
X
12
1.
Based on stakeholder comment, the SDT clarified the applicability language of FAC-001-1 and removed the Generator Owner
from R4. Do you support the proposed redline changes to FAC-001-1? (Please refer to the posted FAC-001-1 technical
justification document for more information about the SDT’s rationale for its changes.)
Summary Consideration:
The SDT thanks all stakeholders for their comments and their 87% approval for the FAC-001-1 changes posted for ballot
in November 2011. Based on stakeholder feedback, the SDT has made the following minor changes to FAC-001-1:
-Corrected a typo in Applicability section 4.2.1 to change “within” to “with.”
-Corrected a typo in the VSLs for R3 to ensure that parts 3.1.1 through 3.1.16 were referenced, rather than just 3.1.1
through 3.1.6.
-Changed references to “Transmission System” to “interconnected Transmission systems” to ensure consistency with the
language elsewhere in the standard and in FAC-002-1.
Some stakeholders remain concerned about the intent of the SDT’s work on FAC-001-1. The SDT reminded them that the
scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with ownership or
operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should first address
“low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”) – that
is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
Through its deliberations, the SDT concluded that an interconnection Facility owned or operated by a GO or GOP that is
more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
Concerned commenters were also referred to one of the SDT’s resource documents: Project 2010-07: Generator
Requirements at the Transmission Interface Background Resource Document.
Some commenters suggested changes to Requirements R1 or R4, which deal exclusively with the Transmission Operator
and are outside the scope of the SDT’s work.
One commenter suggested formatting changes. The SDT agrees with the commenter that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the
standard and no change was made.
One commenter suggested that the phrase “Generator Owner’s existing Facility” be changed to “Generator Owner’s
existing Transmission Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part because in
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
13
some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC.
Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain the
term “Transmission.”
One commenter did not agree with the overall clarifying change to the Applicability section, but the SDT reminded this
commenter that this change was made to address previous comments that indicated that there was uncertainty as to
whether “another Facility to its existing generation Facility” was meant to address connecting additional generators by
the same GO. The SDT intends FAC-001-1 to apply only when the GO of an existing Facility executes an agreement to
evaluate the reliability impact of connecting additional generation owned by another GO. No change made with respect
to this comment.
A few stakeholders were concerned with the 45-day time frame included in the standard. The SDT pointed out that
majority of stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would
simply need to adopt (document and publish) the Facility connection requirements of its TO. No change to that time
frame was made.
Organization
Yes or No
Question 1 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While
the Technical Justification document states that the SDT intended to focus
on a Generator Owner’s radial interconnection facilities, the scope of the
revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
Consideration of Comments: Generator Requirements at the Transmission Interface
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transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis would most likely be
outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Southern Company
No
1) R4 is duplicative of R1 - either remove "maintain" from R1 or delete R4 both instances of "maintain" are not needed.  2) The measures, as
written, provide no additional indication of the evidence that could be
presented to demonstrate compliance with the Reliability Standard
Requirements. They provide little guidance on assessing non-compliance
with the Requirements.  
Response: Thank you for your comment. We agree with your suggestions, but both are outside the scope of this SDT. These items
will be submitted to the Issues Database to be addressed in a future revision of FAC-001.
Southwest Power Pool Standards
Development Team
No
Based on the applicability section of FAC-001 we feel that the strike through
should have been kept. It limited the requirement to just those generator
owners who had agreements in place, which we feel is appropriate.
Response: Thank you for your comment. This change was made to address previous comments that indicated to the SDT there was
uncertainty as to whether this was meant to address connecting additional generators by the same GO. The SDT intends FAC-001
to apply only when the GO of an existing Facility executes an agreement to evaluate the reliability impact of connecting additional
generation owned by another GO. No change made with respect to this comment.
Texas Reliability Entity
No
In Section 5.1, the reference to Regional Entity should be removed. There
are no requirements that apply to the Regional Entity.
In Requirements R1 and R4, “Planning Coordinator” should be added after
“Regional Entity.” In the ERCOT Region it is the Planning Coordinator that
maintains planning criteria and connection requirements. There is no NERC
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requirement or any obligation (as indicated in the technical justification
document) on the part of a GO to specifically execute an Agreement to
evaluate the reliability impact of interconnecting a third party Facility.
Therefore, this requirement’s applicability is contingent on a prerequisite
that may not occur, and that is under the control of the GO. This
assumption on the part of the SDT unnecessarily complicates the
compliance monitoring and enforcement of this standard. For instance, if
an “Agreement” is not executed, a GO is not required to comply with the
requirement, even though the GO may ultimately interconnect with another
entity. The requirement should be modified to include an applicability
trigger similar to that of FAC-002-1, so that once a GO “seek[s] to integrate .
. .,” i.e., agrees to or is compelled to allow a third-party interconnection,
then the requirement becomes applicable. Otherwise, the compliance and
monitoring is subject to the SDT’s speculation as indicated in this language
included in the technical justification document: “However, the SDT cannot
be certain this is the only example and it therefore proposes to add this new
requirement to FAC-001-1. In doing so, the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a
third party to interconnect, have the necessary expertise to conduct the
required interconnect studies to meet this standard. Assuming that a
regulatory body would require a Generator Owner to evaluate such an
interconnection request, the SDT expects the Generator Owner and the
third party to execute some form of an Agreement.”
Response: Thank you for your comment. All of these comments are outside the scope of the SAR and the SDT’s work because they
refer specifically to the sections and requirements that apply to the TO alone. We encourage you to consider submitting a SAR that
addresses your concerns.
Manitoba Hydro
No
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear.
Consideration of Comments: Generator Requirements at the Transmission Interface
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While the Technical Justification document states that the SDT intended to
focus on a Generator Owner’s radial interconnection facilities, the scope of
the revised standard (s) is not confined to such facilities. The very broadly
defined term “Facility” is used. Moreover, the Technical Justification
document’s reference to the FERC decision in Cedar Creek as a basis for the
revision of additional standards is confusing, since that decision did not
specifically address the issue of radial facilities and supported NERC’s
registration of GOs as TOs.
2) If the drafting team intends to limit the scope of FAC-001-1 to GO owned
radial generator interconnection facilities that are not deemed BES
transmission and therefore would not require the registration of the GO as
a TO, Manitoba Hydro disagrees with the proposed changes to FAC-001-1 as
Generator Owners may not have the models or expertise to perform
interconnection studies to determine if there is an impact on the
Transmission Network. This concern is echoed in the technical justification
document provided by NERC: ‘the SDT acknowledges that the Generator
Owner may not, at the time it agrees or is compelled to allow a third part to
interconnect, have the necessary expertise to conduct the required
interconnect studies to meet this standard... the Generator Owner will have
to acquire such expertise. How the Generator Owner chooses to do so is
not for the SDT to determine.’ Although it may not be for the SDT to
determine how a GO obtains technical expertise, ensuring that such
expertise is acquired before a GO conducts the required interconnection
studies should be a concern to NERC as this directly affects the reliability of
the BES. As a result, all interconnection requests should be implemented by
the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User
facility as the TO is in the best position to set unbiased connection
requirements to ensure the reliability of the BES is maintained. If the scope
of FAC-001-1 also applies to GO owned BES transmission facilities, Manitoba
Consideration of Comments: Generator Requirements at the Transmission Interface
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Hydro strongly believes that the Compliance Registry should apply and the
GOs should be required to register as a TO and abide by all applicable
standards to that functional type. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected
TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards,
including the protection standards, are met so the reliability of the BES is
maintained. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively
rare.
3) If the redline changes are implemented, GOs are removed from R4,
thereby removing the obligation for GOs to maintain their connection
requirements. If GOs are included in FAC-001, they should be held
accountable to the same level as TOs and should be required to maintain
their connection requirements. Requiring a GO to maintain connection
requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would
initially be inexperienced in performing interconnection studies and would
benefit from regular and frequent review of their connection requirements
as experience and expertise are gained.
4) The revision to FAC-001-1 R2 may be problematic, depending on what
was intended. Under the revised requirement, the obligation to comply is
dependent on the execution of an agreement to evaluate reliability impacts
under FAC-002-1. However, FAC-002-1 does not clearly require the
execution of an agreement by the Generator Owner. FAC-002-1 only
requires the Generator Owner to “coordinate and cooperate on its
assessments with its Transmission Planner and Planning Authority”.
Accordingly if a Generator Owner coordinates without executing an
agreement to perform an assessment, compliance with FAC-001 R1 will not
Consideration of Comments: Generator Requirements at the Transmission Interface
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be required.
5) Manitoba Hydro would also like to point out that if the redline changes
are implemented, it will greatly increase the complexity of coordination
required under FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP).
The intent of the modifications to this standard is to address the requirements of the GO prior to the interconnection of the third
party to their Facilities. The reliability gap the SDT intends to close is the need for the GO to develop Facility connection
requirements prior to interconnection. The SDT does agree that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
The SDT also refers the commenter to the document titledProject 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document, which is posted on the project page. Specifically, see the last paragraph on page 4 and first two
on page 5.
Tennessee Valley Authority
No
Suggest that the overall structure of the standard be revised such that R1 R3 are applicable to the Transmission Owner (consistent with existing FAC001-0) and R4 (the new requirement) is applicable to the “applicable
Generator Owner”. See further comments below. Support the proposed
revisions to R1 and R4, but suggest R4 be returned to R3 (consistent with
existing FAC-001-0).R3 in the balloted standard should be returned to R2
(consistent with existing FAC-001-0) and only be applicable to the
Transmission Owner. R3.1 (or R2.1 if moved back) should be “fixed”, but it
may be beyond this SDT’s charge. The use of “above” in the FAC-001-0
standard, or the proposed reference to “Requirements R1 or R2” in the
proposed standard do not make sense in combination with the colon used
at the end of the requirement. Suggest that R3.1 (or 2.1 if moved back) be
revised as written below and all sub-requirements of R3.1 be elevated
(R3.1.1 becomes R3.2, R3.1.2 becomes R3.3, etc.).”R3.1 Performance
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requirements and/or planning criteria used to assess system impacts.” R2 in
the balloted standard should become R4 and modified to incorporate the
connection requirements contained in R3 that can more reasonably be
expected of an “applicable Generator Owner”. For instance, an “applicable
Generator Owner” might simply have a connection requirement for a third
party that addresses coordination of system impact studies with the
appropriate Transmission Owner(s), in lieu of R3.1, R3.1.1, and R3.1.2.
Suggest that R2 (or R4 if moved below existing FAC-001-0 requirements) be
revised as written below.”R2 Each applicable Generator Owner that has
agreed to allow a third party Facility owner (Generation Facility,
Transmission Facility, or End-user Facility) to connect to the Transmission
system through use of pre-existing applicable Generator Owner Facilities
shall communicate it’s Facility connection requirements to the third party.
The applicable Generator Owner Facility connection requirements shall
address the following items: R2.1 Coordination of system impact studies
with the Transmission Owner. R2.2 Voltage level and MW and MVAR
capacity or demand at point of connection. R2.3 Breaker duty and surge
protection. R2.4 System protection and coordination R2.5 Metering....” Etc.
Response: Thank you for your comment. We gave the comment due consideration and agree that there are a number of ways to
format the standard with this SDT’s revisions. However, the majority of stakeholders support the current format of the standard.
No change made.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
The intent of the draft language in FAC-001-1 is to provide guidance for
addressing the alleged reliability gap that exists between GO/GOPs that
own/ operate transmission facilities but are not registered as TO/TOPs. The
impact of the revised language will depend on the characterization of the
generator lead after the “third party “ connects to the existing generator
lead. IF the generator lead is owned by the TO utility after the third party
connection : The proposed DRAFT FAC-001 language suggests that within 45
days of a 3rd party having an executed Agreement to evaluate the reliability
Consideration of Comments: Generator Requirements at the Transmission Interface
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impact of interconnecting, the existing generator needs to document and
publish facility connection requirements. The proposed language suggests
that a third party can commandeer existing generators leads and
interconnect. A reclassification would be required because “third party”
power would flow through the downstream portions of the existing leads.
This introduces significant challenges for defining ownership / transfer of
installed assets as well as real property, easements, operational jurisdiction,
O&M cost responsibility, etc.
The FERC approved pro-forma Attachment
X Interconnection Agreement clearly states that the project Developer must
meet all Applicable Reliability Standards which means that all
requirements and guidelines of the Applicable Reliability Councils, and the
Transmission District to which the Developer’s Large Generating Facility is
directly interconnected. As an example, to accommodate this NERC
proposal, the FERC approved NYISO pro-forma tariff would need to be
revised to allow this “third party” use. The pro-forma interconnection tariff
also states that the Developer must provide updated project information
prior to the Facilities Study. The Facilities Study might not be made until
several years after the Interconnection Request /Feasibility Study is made
(“executed Agreement to evaluate the reliability impact of interconnecting”
in this proposed draft is akin to the Interconnection Request/Feasibility
Study). Placing the requirement to have the existing Generator Owner
publish reliability requirements for a potential “third party user”, without
the generator having any knowledge of the potential reliability outcomes or
asset transfer / ownership issues is not a reasonable expectation. The
interconnection of a third party to an existing generator lead would force
existing generators to revise their Interconnection Agreements with FERC.
The “third party”, would at a minimum, need to comply with the existing
Generators reliability obligations as specified in the Interconnection
Agreement.IF the third party connects to the GO owned generator lead, the
GO will be considered a TO:A TO would not be involved, other than review
Consideration of Comments: Generator Requirements at the Transmission Interface
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of the SRIS and Facilities reports. The difficult thing for an existing GO
would be to prepare, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Facility, a document listing the requirements.
To allow for the above possibilities, the language for applicability of FAC001 to GO’s or GOP’s, should be :”Each applicable Generator Owner shall, at
least 60 days prior to execution of a Facilities / Class Year Study Agreement
to evaluate the reliability impact of interconnecting a third party Facility to
the Generator Owner’s existing Facility that is used to interconnect to the
Transmission System, document and publish its Facility connection
requirements to ensure compliance with NERC Reliability Standards and
applicable Regional Entity, sub regional, Power Pool, and individual
Transmission Owner planning criteria and Facility connection
requirements.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Consolidated Edison Co. of NY, Inc.
No
The language for FAC-001 Requirement R2 should be:”This requirement
shall apply to each applicable Generator Owner. Generator Owner filings
must be made at least 60 days in advance of execution of the final
interconnection study agreement in the Planning Coordinator’s or
Transmission Planner’s study process.Each applicable Generation Owner
must publish its Facility connection requirements to ensure compliance with
NERC Reliability Standards and applicable Regional Entity, sub regional,
Power Pool, and individual Transmission Owner planning criteria and Facility
connection requirements.The evaluation of the reliability impact(s) of
interconnecting a third party Facility to the Generator Owner’s existing
Facility utilized for interconnection to the Transmission System must be
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
documented.”
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. The majority of
stakeholders and the SDT support 45 days as a sufficient time frame because in many cases, the GO would simply need to adopt
(document and publish) the facility connection requirements of its TO. No change made.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Unfortunately, the vital point of this requirement revolves around whether
or not a Generator Owner is compelled externally to allow access to their
interconnection facilities. If the GO is driving the connection for financial or
other business reasons, there is no reason they should not be responsible
for developing AND maintaining a facility connection requirements
document. Otherwise, when the local transmission system requirements
change for any reason, there will be no entity responsible to ensure that the
third party will conform as well.Conversely, if the GO should be compelled
to allow access to a third party, it is the responsibility of the “compeller” to
handle all the related reliability studies and documents. This may include
the development of a CFR which separates reliability tasks between the GO
and other entities - especially if a TSP registration is required. This ensures
that the Regional Entity, PUC, RTO, or other regulator must budget dollars
and resources directly related to their action - not cause them to be
directed to a GO.
Response: Thank you for your comment. The SDT agrees with many of the comments (as indicated in the accompanying resource
document titled Technical Justification: FAC-001-1), especially those concerning the complexities of this process. However, the
issues you raise are beyond the scope of the SDT and its SAR. No change made.
PSEG
No
We revised this partial sentence to the following: “Each applicable
Generator Owner shall, within 45 days of having an executed Agreement to
evaluate the reliability impact of interconnecting a third party Facility to the
Generator Owner’s existing Transmission Facility that is used for connection
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
to the interconnected Transmission systems (under FAC-002-1), ...”- The
phrase “Generator Owner’s existing Facility that is used to interconnect to
the Transmission System” was changed to “Generator Owner’s existing
Transmission Facility that is used for connection to the interconnected
Transmission systems.” - “Transmission” was added before Facility to
exclude connections elsewhere; “Transmission System” was changed to
“Transmission systems” because while “Transmission” and “System” are
defined in the NERC Glossary, “System” means “A combination of
generation, transmission, and distribution components.” “Transmission
systems” do not have generation or distribution components, so a lower
case “system” is warranted. - In addition, the suggested phrase
“interconnected Transmission systems” (plural "systems") uses identical
language from FAC-002-1, except that we capitalized “Transmission.
Response: Thank you for your comment. The SDT has addressed the proposed change to applicability according to your comments.
The applicability section now reads: “Generator Owner with an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect to the interconnected
Transmission systems.
The SDT has been informed that in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the
SDT’s attention that in most cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the
GO with FERC. Therefore, the SDT intentionally modified language so that a Facility owned by a generation entity did not contain
the term “Transmission.”
Seattle City Light
Affirmative
Key points are that (1) an executed agreement is required before
evaluations of impacts are necessary and (2) this only applies when a third
party is connecting to the generating interconnection line.
Response: Thank you for your comment.
Electric Power Supply Association
Yes
All TO requirements for FAC-001-1 would apply if and when GO executes
an Agreement to evaluate the reliability impact of interconnecting a third
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
party Facility to its existing generation interconnection Facility. The
execution of the agreement is necessary to comply with FAC-002-1 and start
the compliance clock with the applicable regulatory authority. Thus as the
Project 2010-07 Standard Drafting Team (SDT) in its technical justification
has stated, “If, and only if, the existing owner of a generator
interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing
generation Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s
conclusion.The SDT has examined the issue regarding if future requests for
transmission service on the interconnection Facility and in doing so
acknowledged that when that Facility adopted open access and was
providing transmission service it would necessitate re-evaluation of the
need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary
agreement the SDT contemplates in its technical justification of FAC-001-1.
EPSA believes this serves as the necessary trigger for evaluation of
Requirements 2 and 4 under FAC-001-1 for GOs.
Response: Thank you for your comment.
American Wind Energy Association
Yes
AWEA appreciates that this standard specifies that it has limited
applicability. For instance, only those generators that have an executed
agreement with a third party wishing to interconnect must document and
publish Facility connection requirements. We believe the proposed 45-day
time window is a minimum for GO/GOP owners of generator lead lines to
provide this documentation following execution of such an agreement.
Anything less than 45 days could result in a burdensome and hard to meet
deadline for GO/GOP staff. However, AWEA believes that extending this
time window for publishing Facility connection requirements to 90 days
after an executed agreement would be beneficial. We believe this will allow
the GO/GOP owners of generator leads more time to coordinate with their
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
interconnecting Transmission Providers and will result in more reliable and
coordinated connection requirements for the generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO.
No change made.
SERC OC Standards Review Group
Yes
Please verify within the applicability section (4.2.1) you intended to use the
word “within” rather than some other wording.
Response: Thank you for your comment. The SDT intended it to read “Generator Owner with an executed Agreement to evaluate
the reliability impact of interconnecting a third party Facility to the Generator Owner’s existing Facility that is used to interconnect
to the Transmission System.” This change has been made.
RES Americas Development
Yes
RES Americas and AWEA appreciate that this standard specifies that it has
limited applicability. For instance, only those generators that have an
executed agreement with a third party wishing to interconnect must
document and publish Facility connection requirements. We believe the
proposed 45-day time window is a minimum for GO/GOP owners of
generator lead lines to provide this documentation following execution of
such an agreement. Anything less than 45 days could result in a
burdensome and hard to meet deadline for GO/GOP staff. However, we
believes that extending this time window for publishing Facility connection
requirements to 90 days after an executed agreement would be beneficial.
We believe this will allow the GO/GOP owners of generator leads more time
to coordinate with their interconnecting Transmission Providers and will
result in more reliable and coordinated connection requirements for the
generator lead.
Response: Thank you for your comment. The majority of stakeholders and the SDT support 45 days as a sufficient time frame
because in many cases, the GO would simply need to adopt (document and publish) the facility connection requirements of its TO
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
Yes
We largely agree with the changes the drafting team made but believe
some additional changes are necessary. In section 4.2.1 of the Applicability
Section, “within” should be “with”. Because NERC’s Glossary of Terms
establishes that an Agreement can be verbal and not enforceable by law,
section 4.2.1 should be further modified to clarify that it is a legally
enforceable and fully executed Agreement. The language in R3 in
parenthesis after Generation Owner should be modified to “once required
by Requirement R2”. This makes it clearer that R3 does not apply until the
GO has an executed Agreement to evaluate a request by a third part to
interconnect.
No change made.
ACES Power Marketing Standards
Collaborators
Response: Thank you for your comment. We agree that “within” should be “with”. The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
Southwest Power Pool Regional
Entity
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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American Electric Power
Yes
BP Wind Energy North America Inc.
Yes
Exelon
Yes
Independent Electricity System
Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery Company LLC
Yes
Ameren
Yes
American Transmission Company
Yes
South Carolina Electric and Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 1 Comment
ReliabiltiyFirst
Entergy Services
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 1 Comment
Western Electricity Coordinating
Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power Administration
Consideration of Comments: Generator Requirements at the Transmission Interface
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29
2. Do you support the one year compliance timeframe for Generator Owners as proposed in the Implementation Plan for FAC-001-1?
Summary Consideration:
The vast majority of commenters supported the one year compliance time frame in the Implementation Plan. A few
commenters were concerned with this time frame and associated enforcement, in part based on similar issues addressed
in recent CANs. The SDT did its best to clarify its intent as follows:
The SDT’s intent is that the mandatory date (the date upon which the GO must be compliant with applicable
requirements and measures) be the first calendar day of the first calendar quarter one year after FAC-001-1’s approval.
The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the
mandatory date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those
requirements shall address items under R3.
No changes were made to the Implementation Plan.
Organization
Yes or No
Ingleside Cogeneration LP
(Occidental Chemical)
No
Question 2 Comment
Based upon similar issues addressed in Compliance Application Notices (CANs),
the drafting team needs to specify how the requirements apply to an in-place
“executed Agreement to evaluate the reliability impact of interconnecting a
third party Facility to the Generator Owner’s existing Facility that is used to
interconnect to the Transmission System.” In the view of Ingleside
Cogeneration LP, if the Agreement takes effect even one day before FAC-001-1
does, requirements R2 and R3 do not apply. Without this clarification, it is
possible that NERC’s Compliance team will apply the requirements retroactively
- with minimum industry input.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
Consideration of Comments: Generator Requirements at the Transmission Interface
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Question 2 Comment
address items under R3.
Southwest Power Pool
Regional Entity
No
No action is required unless a GO has an executed third-party agreement. If a
GO has an agreement, the standard already includes a 45-day timeframe for the
GO to document and publish its facility connection requirements.
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
Southern Company
No
See our response to Question 9.
Response: See the SDT’s response to Question 9.
Manitoba Hydro
No
See question 1 comments.
Response: See SDT’s response to Question 1.
Cowlitz County PUD
Yes
Cowlitz PUD (District) registered as a Transmission Owner shortly before FAC001-0 became effective and was forced to file a Mitigation Plan in order to
facilitate compliance. The District successfully completed compliance
implementation and documentation in eight months. The proposed one year
compliance timeframe is sufficient.
Response: Thank you for your comment and support.
Seattle City Light
Yes
The proposed changes for FAC-001-1 state a 45 day period to complete the
evaluation. Not sure what the question is referring to regarding “ 1 year “?
Consideration of Comments: Generator Requirements at the Transmission Interface
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31
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The SDT’s intent is that the mandatory date (the date upon which the GO must be
compliant with applicable requirements and measures) be the first calendar day of the first calendar quarter one year after its
approval. The SDT believes one year is sufficient time for the GO to become compliant where it has one or more in-place (which we
interpret as synonymous with legacy or grandfathered) executed Agreement(s). If an Agreement is executed after the mandatory
date, then the GO has 45 days to “document and publish its Facility connection requirements” (R2) and those requirements shall
address items under R3.
American Wind Energy
Association / RES Americas
Development
Yes
Yes, since there is no exigent reason why this standard needs to be put in place
at once, we support the one-year compliance timeframe. We believe that it will
allow generators a reasonable time to comply with the requirement.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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32
Organization
Yes or No
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
PSEG
Yes
American Transmission
Company
Yes
Question 2 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
33
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Xcel Energy
Yes
Constellation Power Source
Generation
Yes
Question 2 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
Entergy Services
ReliabiltiyFirst
Texas Reliability Entity
Consideration of Comments: Generator Requirements at the Transmission Interface
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34
3.
With respect to FAC-003, many commenters focused on the half-mile qualifier in FAC-003. Some commenters found the halfmile length too short, others found it too long, and still others found the choice among the starting points of the switchyard,
generating station, or generating substation to be confusing. The drafting team attempted to address all of these concerns with
its latest proposed standard changes. The qualifier now reads: “…that extends greater than one mile beyond the fenced area of
the generating station switchyard…” We believe that the one mile length is a reasonable approximation of line of sight, and that
using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion and any discretion on
the part of a Generator Owner or an auditor. Finally, we maintain that it is appropriate to include this qualifier for Generator
Owners because there is a very low risk from vegetation within the line of sight, and thus the formal steps in this standard are
not necessary to ensure reliability of these lines.
Taking into consideration that only one of the versions of FAC-003 will actually be implemented, a decision that will be made as
Project 2007-07—Vegetation Management moves forward, do you support the proposed redline changes to FAC-003-X and FAC003-3?
Summary Consideration:
The SDT thanks all stakeholders for their comments and their over 85% approval for the FAC-003-X and FAC-003-3
changes posted for ballot in November 2011. Based on stakeholder feedback, the SDT has made the following changes:
-Added a clarifying reference to line of sight in the GO exemption in section 4.3.1.
-Corrected a typo in 4.3.1.2 of FAC-003-3.
-Changed “RE” to “Regional Entity” in 4.3.1 of FAC-003-X.
As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally
supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability
benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Consideration of Comments: Generator Requirements at the Transmission Interface
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35
Generator Owner that owns an overhead transmission line(s) that (1) extends greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight from the generating station switchyard
fence to the point of interconnection with a Transmission Owner’s Facility and is operated at 200 kV and above
and any lower voltage lines designated by the Regional Entity as critical to the reliability of the electric system in
the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond the fenced area of
the generating station switchyard to the point of interconnection with a Transmission Owner’s Facility or (2) do
not have a clear line of sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility and are: Operated at 200kV or higher; or operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance that can be seen
by the average person without special instrumentation (e.g., binoculars, telescope, spyglasses, etc.) on a clear day.”
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line
of sight from the switchyard fence to the point of interconnection and are…”
With this reference, the SDT simply seeks to clarify the exception language based on the intent that has been agreed
upon by the stakeholder body. In its Consideration of Comments report from the last formal comment period, which
ended on July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable approximation of line of
sight, and that using a fixed starting point (at the fenced area of the generation station switchyard) eliminates confusion
and any discretion on the part of a Generator Owner or an auditor.” With the addition of an explicit line of sight
reference here, the SDT believes it has clarified its original intent and appropriately considered all comments submitted.
Some stakeholders suggested changes that should have been submitted when Project 2007-07 was revising FAC-003-2,
because these suggestions dealt with the standard as a whole rather than the changes made by this SDT to ensure that
GOs are included in the standard’s applicability.
Consideration of Comments: Generator Requirements at the Transmission Interface
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36
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 3 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of
said line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other
lines. If the GO is only responsible for 0.2 miles, what is the technical basis to ignore
a mile? And would it be the first mile from the switchyard that is ignored, or is the
middle mile, or the last mile where it connects to the TO? Or could the GO decide?
Or could the GO pick sections of the line that amount to a mile that they can ignore?
This seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 3 Comment
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”.
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT chose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
Wisconsin Public Service Corp
Electric Cooperative
Negative
R1.2 refers to an encroachment due to a fall in. This is confusing because according
to the dictionary “Webster’s II” encroachment reads: “to intrude gradually”, and a
‘fall in’ is not usually gradual.
Response: Thank you for your comment. This is outside the scope of the SAR. The SDT reviewed comments submitted as part of the
Project 2007-07 effort and did not find this comment had been submitted.
Wisconsin Public Service Corp.
Negative
The concern with the proposed wording is that many generating station may not
have a “generating station switchyard” as implied by the proposed wording. Often
the generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers the
now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 3 Comment
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: A two
kilometer distance from the controlled area perimeter.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”.
Florida Reliability
Coordinating Council
Negative
There is no technical justification for excluding 1 mile beyond the fence in the
applicability of generators.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
39
Organization
Yes or No
Question 3 Comment
the switchyard fence to the point of interconnection and are…”.
Southern Company
No
 All of these comments pertain to FAC-003-3:
1) We suggest referring to the Implementation Plan in the Effective Date sub-section
of Section A of the standard rather than repeating the content of the
Implementation Plan in the standard. There exists unnessary duplication with
including the information in both places.
2) We suggest simplifying the purpose statement to more succinctly say the intent,
for example: "To maintain a reliable transmission system by managing vegetation
located on transmission rights of way to minimize vegetation encorachments and
thereby minimize the risk of vegetation related outages". If this change is not
acceptable, at least change the phrase "preventing the risk" to "minimizing the risk".
3) We feel that the Enforcement paragraphs between 4.3.1.3 and 5.0 seem to be
out of place. Those paragraphs don’t belong in this location - consider moving them
to Section C. Compliance. The fourth paragraph belongs in the background section.
4) We suggest moving the background section to Section F. "Associated
Documents". It gets in the way of getting to the requirements of the standard.
5) We suggest moving Table 2 of the "Guideline and Technical Basis" document into
R1, since it seems to be the only part of the document that is enforceable. Further
we suggest that the Guideline and Technical Basis document be removed from the
standard. The inclusion of this document in the standard makes the standard
unweildy.
6) We suggest reordering the words in R1 to more clearly state the requirement.
Please consider this rephrasing: "For lines which are either an element of an IROL or
an element of a Major WECC Transfer Path, each applicable TO and applicable GO
shall manage vegetation to prevent encroachments into the MVCD of its applicable
line(s) when operating within their Rating during all Rated Electrical Operating
Conditions of the types shown below:..." (remainder is unchanged).
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 3 Comment
7) We suggest reordering the words of R2 to more clearly state the requirement.
Please consider the this rephrasing: "For lines which are neither an element of an
IROL nor an element of a Major WECC Transfer Path, each applicable TO and
applicable GO shall manage vegetation to prevent encroachments into the MVCD of
its applicable line(s) when operating within its Rating and during all Rated Electrical
Operating Conditions of the types listed below:..." (remainder is unchanged).
8) On Page 11 of the posted clean draft standard, is the reference to the previous
footnote 2 correct? We recommend eliminating footnotes where possible to
minimize redirections.
9) The Rationale text-box on page 13 of the clean version of FAC-003-3 overlaps
some of the text of footnote #6.    
Response: Thank you for your comment.
With respect to your suggestion regarding the implementation plan, the SDT simply followed the NERC-mandated document
guidelines. Making the change you suggest would deviate from that process and thus the SDT has not made it.
With respect to comments 2-8, any standard changes that go beyond making a standard applicable to a GO or GOP are beyond the
scope of this SDT. Any redline changes the SDT has made within standards were made to clarify or qualify the GO or GOP
applicability. These comments would have been more appropriate to make during the comment period for Project 2007-07
Vegetation Management, the project that revised the version of FAC-003 from which this SDT is working.
We have modified the rationale box on page 13 so that it does not overlap with the text of footnote 6.
Dominion
No
Dominion suggests in FAC-003-X; 4.3.1. Regional Entity be changed to RE as listed in
4.2.1 for consistency. Also Regional Entity is used throughout the rest of the
document, suggest using RE for consistency overall. Dominion suggests in FAC-003-3;
4.3.1. adding station to the following “ Overhead transmission lines that extend
greater than one mile or 1.609 kilometers beyond the fenced area of the generation
station switchyard and are” to show consistency as it is written in FAC-003-X
4.3.1.Further, Dominion is concerned that the technical justification characterized
the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced area of the
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
41
Organization
Yes or No
Question 3 Comment
generating station switchyard) as “approximate line of sign [sic] from a fixed point”
and notes that this line of sight may be limited by local terrain. Where line of sight of
the radial corridor is limited on a clear day due to terrain, the one mile exemption
must be limited in distance to no more than the line of sight on a clear day beyond
the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…” .
Exelon
No
FAC-003 - Exelon supports the one mile length qualifier, but feels that additional
clarification is needed to determine the points of demarcation. There are too many
differing physical configurations to use a “fence line” as a determination of
applicability. Suggest that the tie line length be defined as “from the Generator Step
up Transformer GSU to the point of interconnection between the GO and TO owned
equipment.” Also suggest that the standard define what constitutes a generation
station switchyard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
42
Organization
Yes or No
Question 3 Comment
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Ingleside Cogeneration LP is very concerned that the attempt to develop “brightline” criteria to assign applicability to either version of FAC-003 is misplaced. As seen
with NERC’s recent proposed directive related to Generator-Transmission
interconnections, those thresholds can be arbitrarily reduced based upon regulators
aversion to risk - not scientific evidence. (As it stands today, NERC has proposed any
interconnection facility operating at 100 kV or higher and greater than 3 spans in
length be applicable - which is even stricter than the TO thresholds in FAC-003.)This
would suggest that a reliability assessment consistent with the TPL standards must
be the determining factor. If the Planning Coordinator or Transmission Planner can
show that the Generator-Transmission interconnection could contribute to a
violation of an SOL or IROL, then a vegetation management program may be in
order.Furthermore, there needs to be some level of common sense applied if a GOTO interconnection is located in an area where vegetation clearance is never an
issue. A one-size-fits-all requirement based upon vegetation growth in the subtropics, should not automatically apply in the desert. In our view, every dollar spent
to control vegetation in an arid climate is one less dollar available to purchase
advanced telemetry, AGC systems, and other items which have a far greater impact
on reliability.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
Consideration of Comments: Generator Requirements at the Transmission Interface
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43
Organization
Yes or No
Question 3 Comment
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”.
The SDT also took into consideration the stakeholder comments submitted and believes this exemption adequately addresses the
reliability impact for a majority of the Facilities, while balancing the efforts necessary to support the standard from all entities.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in this project. If a
Generator Owner is required to register as a TO, all the Requirements applicable to a
TO should apply. There is no need to change specific Reliability Standards to allow
the Generator Owner to perform only selected TO functions.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT also
refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface Background
Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
No
Suggest in FAC-003-X; 4.3.1. that Regional Entity be changed to RE as listed in 4.2.1
for consistency. Also Regional Entity is used throughout the rest of the document,
suggest using RE for consistency.In FAC-003-3; 4.3.1. add station to the following: “
Overhead transmission lines that extend greater than one mile or 1.609 kilometers
beyond the fenced area of the generation station switchyard and are” to show
consistency as it is written in FAC-003-X 4.3.1.The technical justification
characterized the exclusion (i.e., one mile or 1.609 kilometers beyond the fenced
area of the generating station switchyard) as “approximate line of sight [sic] from a
fixed point” and noted that this line of sight may be limited by local terrain. Where
line of sight of the radial corridor is limited on a clear day due to terrain, the one mile
exemption must be limited in distance to no more than the line of sight on a clear
day beyond the fenced area.
Response: Thank you for your comment. The SDT agrees with your comment about the Regional Entity, but will instead use Regional
Entity throughout.
Consideration of Comments: Generator Requirements at the Transmission Interface
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44
Organization
Yes or No
Question 3 Comment
Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator Requirements at
the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the overhead portion
is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry comments support the
position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”.
MRO NSRF
No
The NSRF agrees with the drafting committees desire to eliminate arbitrary and
capricious behavior of auditors and industry staff by precisely defining the point at
which measurement starts for the length of transmission line. The concern the NSRF
has with the proposed wording is that many generating station may not have a
“generating station switchyard” as implied by the proposed wording. Often the
generator leads (e.g. 20 kV) will exit the generator and connect to transformers
located in transformer bays directly adjacent to the plant. From the transformers
the now greater than 200 kV lines will be routed to the point of interconnect or a
generating unit switchyard, possibly miles or yards away. By no one’s definitions
would the transformer bays adjacent to the plant be considered a switchyard. The
plant fence may be yards or hundreds of yards from the bays and on a multiple unit
site, there may be a site fence or boundary, which could be comprise of fences,
security patrols, or other barriers yards or miles from the transformer but enveloping
the switchyard. The valid assumption made by the drafting team is that transmission
lines within an area tightly controlled by the generator operator poses very little risk
to the BES as a result of vegetation contact. This assumption is based on the valid
observation that these areas are routinely occupied and observed by station
personnel and as a result unexpected and unacceptable vegetation growth is highly
unlikely because it is controlled by routine maintenance. It also correctly assumes
that some distance past the controlled area is acceptable since this area would also
be under near continuous observation. The problem comes in defining both a tightly
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
45
Organization
Yes or No
Question 3 Comment
controlled area and a line of site. We suggest the following: Controlled Area: A
perimeter around a power plant, power plants, or switchyard which is prevents
intrusion by the use of physical barriers, observation, or electronic monitoring and is
routinely occupied such that unexpected and unacceptable vegetation growth would
be observed and correct as a matter of routine maintenance. Line of Sight: NSRF
recommends a two kilometer distance from the controlled area perimeter. Our
assessment is that an individual of average height would have a line of site of
approximately 4 Kilometers. Therefore, we recommended a distance of 2 kilometers
from the Controlled Area of the plant to provide margin. The revised applicability
statement would read as follows: “Generator Owner that owns an overhead
transmission line(s) that extends greater than 2.0 kilometers beyond the Controlled
Area of the generating station up to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric system in
the region. Furthermore we applaud the committee for using the metric system to
identify the acceptable distance for this standard and urge it to remove all
references to English units. We strongly suggest this drafting team and all future
drafting team abandon the anachronistic English measurement system. This archaic
system, based on the length of an average barley corn, should be abandon in all
scientific and engineering endeavors.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”.
Consideration of Comments: Generator Requirements at the Transmission Interface
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46
Organization
Yes or No
Southwest Power Pool
Standards Development Team
No
Question 3 Comment
There is a possibility of some conflict with the Bulk Electric System Definition. This
should be consistent with the Transmission Owner requirements if the lead is
determined part of the BES.
Response: Thank you for your comment. The SDT intended this standard to be applied to Facilities of GO and TO equally, with the
exception of the distance exemption for a generator interconnection Facility. The SDT also notes that FAC-003-2 (approved by the
NERC’s Board of Trustees on Nov. 3, 2011) does not rely upon the BES definition to determine the facility to which this standard
applies (200 kV or higher, or IROL or WECC Transfer Path).
South Carolina Electric and
Gas
No
There should be no qualifying exemption to FAC-003 for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
from the switchyard fence to the point of interconnection and are…”.
SERC Planning Standards
Subcommittee
No
We believe there should be no exemption for Generator Owners.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight
Consideration of Comments: Generator Requirements at the Transmission Interface
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47
Organization
Yes or No
Question 3 Comment
from the switchyard fence to the point of interconnection and are…”.
PSEG
No
Infigen Energy US
Affirmative
Infigen finds the DST supporting details regarding FAC-003-X to be appropriate. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
Seattle City Light
Affirmative
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Response: Thank you for your comment and support.
RES Americas Development /
American Wind Energy
Association
Yes
Applying the vegetation management requirements to only generator lead lines that
extend more than “one mile beyond the fenced area of the generating station
switchyard” strikes a reasonable balance among the many stakeholder positions
expressed on this topic. We think that as this criterion recognizes that there is little
need for a vegetation management plan for shorter lines, it should explicitly state
that this is true for all such facilities with lines of that length or smaller.
Response: Thank you for your comment and support.
Texas Reliability Entity
Yes
In the description of the “second effective date” in FAC-003-X there is an erroneous
reference to “Requirement R3,” which should be corrected to “Requirement R1.”
Response: Thank you for your comment and support. This conforming change was made.
Seattle City Light
Yes
Key points are the greater than one mile with clear statement of “...beyond the
fenced area of the generating switchyard.”
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 3 Comment
Response: Thank you for your comment and support.
ACES Power Marketing
Standards Collaborators
Yes
We support the changes to FAC-003 suggested by the drafting team because we
believe the drafting team has provided the best solution in face of a difficult
problem. However, in general, we do not support registration of GOs and GOPs as
TOs and TOPs or applicability of any TO/TOP requirements to the GO/GOP simply
because they have a radial interconnection greater than one mile in length. While
there may be some generators that own interconnecting facilities of significant
length operated at a significant voltage that could impact BES reliability, we do not
believe that the number of generating facilities that fit into that category is
significantly large. When one considers that the majority of generators are still
owned and operator by utilities that are also registered as a TO and TOP, there is
only a minority subset of generators left that could be considered. NERC has the
registration for this remaining set of generators and could use the data to evaluate
how many of this remaining subset have interconnections owned by the generator
that are substantial enough to affect reliability. It seems that NERC could determine
the boundaries of this problem before registering anymore GOs and GOPs as TOs and
TOPs or before applying additional requirements through this effort on the GOs and
GOPs.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Regional Entity
Yes
Florida Municipal Power
Agency
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 3 Comment
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 3 Comment
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of
NY, Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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4.
Do you support compliance timeframe for Generator Owners as included and explained in the Implementation Plans for
FAC-003-X?
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-X.
One commenter found a typo in the effective dates section of FAC-003-X, where one section referenced R3 when it
should have referenced R1. That has been corrected in both the standard and the Implementation Plan.
A few stakeholders thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Beyond the corrected typo, no changes were made.
Organization
Yes or No
Ameren Services
Negative
Question 4 Comment
The 2 year compliance time line is far too long. There is significant industry evidence
that was developed in the drafting of Version 2 that supports a one year compliance
time-line for new lines. This is evidenced in Version 2. Thus there is no basis for the 2
years.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Texas Reliability Entity
No
A compliance timeframe for the applicable GOs of two years is too long and the
scenario used as a basis provides no timing specifics or details. Moreover, the 12
months for an existing transmission line operated at 200kV or higher which is newly
acquired by an asset owner and which was not previously subject to this standard is
arguably the same situation as an applicable GO but the applicable GO has an
additional 12 months to come into compliance.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so. The SDT does not believe
that a TO’s acquisition of a new asset is the same as applying new requirements to a GO.
Ingleside Cogeneration LP
(Occidental Chemical)
No
Based upon similar issues addressed in Compliance Application Notices (CANs), the
drafting team needs to specify when the first vegetation management inspection
quarterly report, and any other requirement with an assigned interval in FAC-003-3 or
FAC-003-X. Even if the decision is to adopt the same criteria proposed in CAN-0012,
the industry is better served with a clear distinction made up front.
Response: Thank you for your comment. This is a comment that is outside the scope of the SDT, and in fact deals with a larger body of
standards than just FAC-003. No change made.
PSEG
No
It’s no longer applicable.
Response: Thank you for your comment. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
– Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Manitoba Hydro
No
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southwest Power Pool
Standards Development Team
No
The effective dates should be consistent with the original standard. If there is a
reason for the extension we would like to know why.
Response: Thank you for your comment. The SDT choose the time in the implementation plan based upon comments of stakeholders
and the fact that the implementation plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a
translation and clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies
and standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their existing
procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to assume that GOs,
having never had to comply with a vegetation management standard, be afforded adequate time to do so.
Southern Company
Yes
The development of a working TVMP will take some time to initialize. The 1 year time
frame for R3 is appropriate. The 2 year time frame for all other requirements is
appropriate.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
Seattle City Light
Yes
The explanation deals with the fact that there are simultaneous revisions of FAC-003
underway by two different teams.
Response: Thank you for your comment and support.
MRO NSRF
Yes
There may be a typographical error on the effective date. As currently drafted the
standard states: In those jurisdictions where regulatory approval is required,
Requirement R1 applied to the Generator Owner becomes effective on the first
calendar day of the first calendar quarter one year after the date of the order
approving the standard from applicable regulatory authorities where such explicit
approval for all requirements is required. In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees adoption. Should it be worded
as follows? In those jurisdictions where regulatory approval is required, Requirement
R1 applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees adoption.
Response: Thank you for your comment. The SDT agrees with you. “Requirement R3,” will be corrected to “Requirement R1.”
RES Americas Development/
American Wind Energy
Association
Yes
Yes, as with our comments to question 2, since there is no exigent reason why this
standard needs to be put in place at once, we support the proposed compliance
timeframe. We believe that it will allow generators a reasonable time to comply with
the requirement.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 4 Comment
America Inc.
Exelon
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
Sempra Generation
Yes
Entergy Services
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Western Electricity
Coordinating Council
Consideration of Comments: Generator Requirements at the Transmission Interface
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57
Organization
Yes or No
Question 4 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Tennessee Valley Authority
Consideration of Comments: Generator Requirements at the Transmission Interface
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58
5. In the FAC-003-3 implementation plan, the SDT has attempted to account for a number of different scenarios that could play out
with respect to the filing and approvals of FAC-003-2 and FAC-003-3. Do you support this approach? If there are other scenarios
that the SDT needs to account for, please suggest them here.
Summary Consideration:
The SDT thanks all stakeholders for their comments. The vast majority of stakeholders support the compliance
timeframes as proposed and explained in the Implementation Plan for FAC-003-3.
One commenter thought that two years was too long for an Implementation Plan for this standard. The SDT reminded
those commenters that the time frame was based on previous stakeholder comments and the fact that the
Implementation Plan for Version 0 standards stated “the Version 0 Reliability Standards are generally a translation and
clarification of existing operating policies and planning standards, entities that are incompliance with NERC policies and
standards today are expected to be able to remain in compliance with the Version 0 Reliability Standards with their
existing procedures, tools, and practices.” This process occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do
so.
Some stakeholders expressed confusion about the relationship between FAC-003-3 and the recently BOT-approved FAC003-2. The SDT acknowledges that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission
Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff
will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for
both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERCapproved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X
through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
All stakeholders should note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but
stakeholders should not vote as though they are choosing one or the other. As stated above, the SDT plans to present
FAC-003-3 alone to NERC’s Board of Trustees, but it wants to have FAC-003-X ready to submit to the Board if, for some
reason, neither FAC-003-2 nor FAC-003-3 are approved by FERC. Members of the ballot body should vote on the merits of
each version of FAC-003 individually. In other words, stakeholders who support adding GOs to the applicability of FAC003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Manitoba Hydro
No
Question 5 Comment
See question 3 comments.
Response: See the SDT’s response to Question 3.
Southern Company
No
We believe that a standard development process should not have parallel paths where
the same version is being modified by multiple teams. The uncertainty in which
development path leads to confusion in the industry and ultimately proves to have
wasted come resources for the path that does not come to fruition.
Response: Thank you for your comment. While the SDT agrees this is not preferable, it was necessary given the urgency of both
projects. The SDT did the best it could to describe the scenarios and reasons for posting multiple versions.
In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation Management (developed under Project
2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with the applicable regulatory authorities.
The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and
FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually only filing FAC-003-3. The SDT has
elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved by FERC, the SDT wants to be
ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation on the piece of line commonly
known as the generator interconnection Facility.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration agrees that the SDT’s approach is thorough. We are far more
concerned about FAC-003’s applicability criteria and implementation time frame at
this point - as stated in our responses to questions 3 and 4.
Response: Thank you for your comment and support. Please refer to the SDT’s responses to Questions 3 and 4.
ACES Power Marketing
Standards Collaborators
Yes
With recent NERC BOT approval of the FAC-003-2 standard, the drafting team should
continue to monitor the standard progress with FERC and make necessary
adjustments to the implementation plan.
Response: Thank you for your comment. The SDT acknowledges that FAC-003-2 was recently approved by the BOT. The SDT does not
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
see the need to revise the GO implementation plan, as it already accounts for a number of scenarios that could occur based on how
FERC handles the filing of FAC-003-2.
Ameren
(a) There is no technical basis for the one mile length exemption. In fact, one could
argue that a very short line, 300 feet in length, that experienced a fault from a tree at
"the end of the circuit", i.e near the switchyard fence, would have much more of an
impact on the BES because the fault would be limited by much less impedance.
(b) It is also unclear in this version if a GO that owned one line that was 1.2 miles in
length would have to comply for the entire length of said line, or just 0.2 miles of said
line. If the GO is responsible for 1.2 miles, then that argues that the first mile is
important and consequently there is no basis for ignoring the first mile on other lines.
If the GO is only responsible for 0.2 miles, what is the technical basis to ignore a mile?
And would it be the first mile from the switchyard that is ignored, or is the middle
mile, or the last mile where it connects to the TO? Or could the GO decide? Or could
the GO pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(c) The 2 year compliance time line is far too long. There is significant industry
evidence that was developed in the drafting of Version 2 that supports a one year
compliance time-line for new lines. This is evidenced in Version 2. Thus there is no
basis for the 2 years
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”.
With respect to your second comment, the SDT intended for the length qualifier to be just that; if the overhead portion of a Facility
Consideration of Comments: Generator Requirements at the Transmission Interface
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Organization
Yes or No
Question 5 Comment
exceeds the distance, the entire Facility is subject to the requirements of the standard.
The SDT choose the time in the implementation plan based upon reasons it documented in the accompanying implementation plan
and also based upon comments of stakeholders.
PSEG
Yes
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Florida Municipal Power
Agency
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
Consideration of Comments: Generator Requirements at the Transmission Interface
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62
Organization
Yes or No
American Wind Energy
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Gas
Yes
RES Americas Development
Yes
Sempra Generation
Yes
Entergy Services
Yes
Question 5 Comment
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63
Organization
Yes or No
Xcel Energy
Yes
Cowlitz County PUD
Yes
Texas Reliability Entity
Yes
Constellation Power Source
Generation
Yes
Tennessee Valley Authority
Yes
Question 5 Comment
Southwest Power Pool
Regional Entity
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Consolidated Edison Co. of NY,
Inc.
ReliabiltiyFirst
Consideration of Comments: Generator Requirements at the Transmission Interface
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64
6. In its technical justification document, the SDT reviews all standards that had been proposed for substantive modification in the
Ad Hoc Group’s original support and explains why, with the exception of FAC-003, modifying them would not provide any
reliability benefit. Do you support these justifications? If you believe the SDT needs to add more information to its rationale for
any of these decisions, please include suggested language here.
Summary Consideration:
The SDT thanks all stakeholders for their comments.
A few commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit reference to a
generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing revisions to PRC-005-1a and
will post them soon.
Many commenters encouraged the SDT to reexamine the standards and requirements that FERC and NERC applied to
GOs and GOPs in their Milford/Cedar Creek order and draft compliance directive regarding generator leads. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider
the content of the proposed directive.
Based on stakeholder comments, the SDT expanded its technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft
compliance directive. After another thorough review of these standards, the SDT continues to believe that there are clear
and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
One commenter remains concerned about the scope of the SDT. The SDT reminded this commenter that its scope is
addressed in the SAR and that its intent is to address all reliability gaps associated with ownership or operation of an
interconnection Facility by a generation entity (GO/GOP). The SDT also refers the commenter to the document titled
Project 2010-07: Generator Requirements at the Transmission Interface Background Resource Document. Specifically, see
the last paragraph on page 4 and first two on page 5.
Organization
Yes or No
Question 6 Comment
Manitoba Hydro
Negative
The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
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Organization
Yes or No
Question 6 Comment
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
Texas Reliability Entity
No
Our negative votes on FAC-003 reflect our concern that this project has not
considered all of the applicable standards. Why did the SDT choose to only review the
Ad Hoc Group’s standards when there have been multiple registration appeals in
which FERC and NERC have repeatedly cited specific additional TO/TOP standards that
were determined to be applicable to GO/GOPs? This SDT project would serve a
tremendous value to the ERO and in particular industry if it were to address the
technical aspects of the following FERC ordered applicable standards: PRC-001-1 R2,
R4; PRC-004-1 R1; TOP-004-2 R6; PER-003-1 R1; FAC-003-1 R1, R2; TOP-001-1a R1 and
FAC-004-2 R2. The SDT team should analyze the FERC orders, the applicable
standards indicated, and the circumstances and facts involved, and technically justify
why no reliability gap exists if these standards are not applied to GO interface
facilities. The SDT should include more “technical” information in its technical
justification document. For example, in regards to TOP-004-2 R7, the SDT technical
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Question 6 Comment
justification states that there is no reliability gap because, “. . . because an operator
has a fiduciary obligation to protect a Facility for which it is operationally
responsible.” An entity having a fiduciary obligation is not a technical justification of
why a reliability gap does not exist. Moreover, by that logic there would be no need
for many standards because every registered entity has a fiduciary obligation to
protect its facilities.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
We would like to clarify, in response to the comment concerning TOP-004-2 R7, that in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface” the SDT also stated “FAC-008-1—Facility Ratings
Methodology and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for establishing a ratings
methodology and communicating facility ratings to the Reliability Coordinator, Planning Authority, Transmission Planner, and
Transmission Operator is for use in reliable planning and operation of the Bulk Electric System.”
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
PSEG
No
PRC-005-1 - Transmission and Generation Protection System Maintenance and
Testing was recommended by the Ad Hoc Group for modification, but not addressed
to the technical justification document. It should be.
Response: Thank you for your comment. We have reviewed PRC-005-1a and believe that the wording in R1 and R2 of that standard
require the same explicit reference to a generator interconnection Facility that was added in PRC-004-2a R2. The SDT is developing
revisions to PRC-005-1a and will post them soon.
Florida Municipal Power
No
see comment to Question 7
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Question 6 Comment
Agency
Response: See the SDT’s response to Question 7.
Manitoba Hydro
No
See Question 7 comments.
Response: See the SDT’s response to Question 7.
MRO NSRF
No
The NSRF has one concern with the current justification and definitions. At some
point, if enough interconnections are made to generator outlet leads in accordance
with FAC-001, the original generator operator will be a Transmission Operator and a
Transmission Owner. This point in time needs to be explicitly defined by the drafting
team.
Response: The SDT cannot act on this comment. Registration is outside the scope of this SDT and resides with NERC and the Regional
Entity.
Manitoba Hydro
If the drafting team intends to limit the scope of FAC-001-1 to GO owned radial
generator interconnection facilities that are not deemed BES transmission and
therefore would not require the registration of the GO as a TO, Manitoba Hydro
disagrees with the proposed changes to FAC-001-1 as Generator Owners may not
have the models or expertise to perform interconnection studies to determine if
there is an impact on the Transmission Network. This concern is echoed in the
technical justification document provided by NERC: ‘the SDT acknowledges that the
Generator Owner may not, at the time it agrees or is compelled to allow a third part
to interconnect, have the necessary expertise to conduct the required interconnect
studies to meet this standard... the Generator Owner will have to acquire such
expertise. How the Generator Owner chooses to do so is not for the SDT to
determine.’ Although it may not be for the SDT to determine how a GO obtains
technical expertise, ensuring that such expertise is acquired before a GO conducts the
required interconnection studies should be a concern to NERC as this directly affects
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Question 6 Comment
the reliability of the BES. As a result, all interconnection requests should be
implemented by the TO providing the GO with connection to the BES regardless if the
interconnection point is within a Generation Owner facility or End-User facility as the
TO is in the best position to set unbiased connection requirements to ensure the
reliability of the BES is maintained. If the scope of FAC-001-1 also applies to GO
owned BES transmission facilities, Manitoba Hydro strongly believes that the
Compliance Registry should apply and the GOs should be required to register as a TO
and abide by all applicable standards to that functional type. There is no need to
change specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions. Reliability gaps would be better addressed if select GOs and
GOPs registered as TOs and TOPs to ensure all reliability standards, including the
protection standards, are met so the reliability of the BES is maintained. At this time,
this would not lead to a large number of extra registrations since, as stated in the
technical justification document, ‘interconnection requests for Generator Owner
Facilities are still relatively rare.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs. The SDT does agree that upon interconnection of a third party, other standards or registrations
may apply as appropriate.
Electric Power Supply
Association
Affirmative
All TO requirements for FAC-001-1 would apply if and when GO executes an
Agreement to evaluate the reliability impact of interconnecting a third party Facility
to its existing generation interconnection Facility. The execution of the agreement is
necessary to comply with FAC-002-1 and start the compliance clock with the
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Question 6 Comment
applicable regulatory authority. Thus as the Project 2010-07 Standard Drafting Team
(SDT) in its technical justification has stated, “If, and only if, the existing owner of a
generator interconnection Facility has an executed Agreement to evaluate the
reliability impact of interconnecting a third party Facility to its existing generation
Facility” then FAC-001-1 should apply. EPSA concurs with SDT’s conclusion. The SDT
has examined the issue regarding if future requests for transmission service on the
interconnection Facility and in doing so acknowledged that when that Facility adopted
open access and was providing transmission service it would necessitate re-evaluation
of the need for the Facility to be maintained in accordance with FAC-001-1,
Requirements 2 and 4. This service would indeed prompt the necessary agreement
the SDT contemplates in its technical justification of FAC-001-1. EPSA believes this
serves as the necessary trigger for evaluation of Requirements 2 and 4 under FAC001-1 for GOs.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen supports the FAC-001-1 technical analysis by the Project 2010-07 SDT, which
states in part that “If, and only if, the existing owner of a generator interconnection
Facility has an executed Agreement to evaluate the reliability impact of
interconnecting a third party Facility to its existing generation Facility would the
proposed FAC-001-1 apply”. We agree with the SDT’s reasoning that if the owner of
the existing generator interconnection Facility agrees, or is compelled to allow a third
party to interconnect, but can do so using existing agreements, contracts, and/or
tariffs [to avoid requiring additional executed Agreement(s)], this is the most prudent
and effective way to manage this process with continuity. In order to evaluate the
reliability impact of interconnecting a third party Facility to the Generator Owner’s
existing Facility more expediently, it can avoid having to develop its own connection
requirements or perform additional impact studies, to the extent possible. We find it
reasonable to negotiate with the existing Transmission Owner, Transmission Planner,
and/or Transmission Service Provider to manage this requirement, utilizing their
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Question 6 Comment
existing processes and Agreements for the purpose of fulfilling FAC-001-1.
Response: Thank you for your comment and support.
Southern Company
Yes
Additional responses are needed to justify the exclusion of the list of requirements
and standards found in the recent FERC order denying the rehearing request of the
Compliance Registry Appeals of Cedar Creek and Milford. (135 FERC Para. 61,241).
Please see our response to Question 10 for a detailed discussion on this
topic.   
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
Based on your and other comments, we have expanded our technical justification document (posted under “Supporting Materials”) to
include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After
another thorough review of these standards, the SDT continues to believe that there are clear and technical reliability-based reasons
that support not adding GO and GOP requirements to these standards.
Constellation Power Source
Generation
Yes
Constellation supports the SDT justifications and offers additional information in our
response to question 10.
Response: Thank you for your comment and support.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Ingleside Cogeneration LP believes the SDT has spent a significant amount of time and
effort to demonstrate that only FAC-001, FAC-003, and PRC-004 need to be modified
to address any reliability gaps that may exist related to the GO-TO interconnection.
We agree that the other standards/requirements identified by the Ad Hoc Group are
covered elsewhere.
Response: Thank you for your comment and support.
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Organization
Yes or No
American Wind Energy
Association
Yes
Question 6 Comment
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
RES Americas Development
Yes
The reasoning of the SDT is comprehensive and makes a strong case for why there is
no need for additional standards to be applied to GO/GOP lead lines as they will not
improve the reliability of the Bulk Electric System. In fact, as noted above, such
additional standards may decrease reliability by diverting the GO/GOP’s resources
from the operation of the equipment that actually produces electricity - the
generation equipment itself.
Response: Thank you for your comment and support.
SERC OC Standards Review
Group
Yes
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
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Organization
Yes or No
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Standards Collaborators
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Company
Yes
South Carolina Electric and
Yes
Question 6 Comment
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Question 6 Comment
Gas
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Western Electricity
Coordinating Council
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
Independent Electricity
System Operator
Ameren
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
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Question 6 Comment
Tennessee Valley Authority
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7. The SDT is attempting to modify a set of standards so that radial generator interconnection Facilities are appropriately accounted
for in NERC’s Reliability Standards, both to close reliability gaps and to prevent the unnecessary registration of GOs and GOPs at
TOs and TOPs. Does the set of standards currently posted achieve this goal?
Summary Consideration:
The SDT thanks all stakeholders for their comments. Most commenters support the SDT’s work and agree that the set of
standards for which the SDT has proposed modification ensure that radial generator interconnection Facilities are
appropriately accounted for in NERC’s Reliability Standards.
One commenter continues to express confusion about the scope of the SDT’s work in general. The SDT reminded this
commenter that its scope is addressed in the SAR. The intent of the SAR is to address all reliability gaps associated with
ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it
should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a
transmission entity (TO/TOP). Through its deliberations, the SDT came to the conclusion that an interconnection Facility
owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT. The SDT also refers the commenter to the document titled Project
2010-07: Generator Requirements at the Transmission Interface Background Resource Document (specifically, the last
paragraph on page 4 and first two on page 5). The SDT has proposed the modification of a select set of standards so that
they apply to GOs and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been
widely supported by the stakeholder body. The SDT does agree that upon interconnection of a third party, other
standards or registrations may apply as appropriate.
One commenter asked the SDT to specify what it means by “radial.” By “radial generator interconnection Facilities,” the
SDT means sole-use Facilities (see posted examples under “Supporting Materials”) – that is, a Facility used to connect one
or more generators to a Facility owned or operated by a transmission entity (TO/TOP).
A few commenters suggested that the SDT address those standards cited by FERC and NERC in related projects. The SDT
pointed out that the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that
don’t include explicit directives), or NERC directives, within the standards process. However, based on staekolder
comments, the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include
any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
After another thorough review of these standards, the SDT continues to believe that there are clear and technical
reliability-based reasons that support not adding GO and GOP requirements to these standards.
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One commenter suggested that the SDT include the GO in TOP-004-2 R6, but the SDT continues to maintain that no gap
exists because TOP-002-2 R3 already requires the GO to coordinate with its host BA and TSP, who in turn are required to
coordinate with their TOPs.
One commenter pointed out that the Data Retention section of the proposed PRC-004-2.1a also requires modification to
include the generator interconnection Facility. The SDT agrees and made this change.
Organization
Yes or No
Manitoba Hydro
Negative
Question 7 Comment
Manitoba Hydro has the following comments:
1) The intention of the NERC SDT in revising these standards is not clear. While the
Technical Justification document states that the SDT intended to focus on a Generator
Owner’s radial interconnection facilities, the scope of the revised standard (s) is not
confined to such facilities. The very broadly defined term “Facility” is used. Moreover,
the Technical Justification document’s reference to the FERC decision in Cedar Creek
as a basis for the revision of additional standards is confusing, since that decision did
not specifically address the issue of radial facilities and supported NERC’s registration
of GOs as TOs.
2) Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry
and only having a limited set of standards apply to the GOs ‘interconnection facilities’
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
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Question 7 Comment
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Manitoba Hydro
Negative
Manitoba Hydro strongly disagrees with bypassing the NERC Compliance Registry and
only having a limited set of standards apply to the GOs ‘interconnection facilities’ If a
Generator Owner wants to own transmission facilities and it falls under the definition
of a Transmission Owner under the NERC Registry Criteria, then all the Requirements
applicable to a TO should apply. There is no need to change specific Reliability
Standards to allow the Generator Owner to perform only selected TO functions.
Reliability gaps would be better closed if select GOs and GOPs simply registered as
TOs and TOPs. At this time, this would not lead to a large number of extra
registrations since, as stated in the technical justification document, ‘interconnection
requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The SDT has proposed the modification of a select set of standards so that they apply to GOs
and GOPs as an alternative to registering all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the
stakeholder body. The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as
appropriate.
PSEG
No
It would be helpful if the SDT defined what it means by the term “radial generator
interconnection Facilities.” Does it mean interconnection Facilities that under Normal
Clearing for a fault do not interrupt flows on other BES Elements? This is also
confusing because of the radial exclusion included in the BES definition work in
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Question 7 Comment
Project 2010-17. That definition would allow part of a three-terminal circuit to be
excluded from the BES, while the other parts are included in the BES.
Response: Thank you for your comment. By “radial generator interconnection Facilities,” the SDT means sole-use Facilities (see posted
examples under “Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated
by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or
operated by a GO/GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside
the scope of this SDT.
Texas Reliability Entity
No
See comment 6.
Response: See the SDT’s response to Question 6.
Manitoba Hydro
No
The SDT’s proposed modifications gives special treatment to the Generator Owner in
that it allows the Generator Owner TO status for a couple of standards (FAC-001, FAC003 and PRC-004), but exempts the Generator Owner from many of the standards
applicable to a TO. The NERC Registry Criteria defines the various functional entities.
If a Generator Owner wants to own transmission facilities and it falls under the
definition of a Transmission Owner under the NERC Registry Criteria, then all the
Requirements applicable to a TO should apply. There is no need to change specific
Reliability Standards to allow the Generator Owner to perform only selected TO
functions. Reliability gaps would be better closed if select GOs and GOPs simply
registered as TOs and TOPs. At this time, this would not lead to a large number of
extra registrations since, as stated in the technical justification document,
‘interconnection requests for Generator Owner Facilities are still relatively rare.
Response: Thank you for your comment. The scope of this SDT is addressed in the SAR. The intent of the SAR is to address all
reliability gaps associated with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT
determined that it should first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under
“Supporting Materials”) – that is, a Facility used to connect one or more generators to a Facility owned or operated by a transmission
entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection Facility owned or operated by a GO or
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Question 7 Comment
GOP that is more complex would likely require specific analysis and that such analysis would most likely be outside the scope of this
SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission Interface
Background Resource Document. Specifically, see the last paragraph on page 4 and first two on page 5.
The SDT has proposed the modification of a select set of standards so that they apply to GOs and GOPs as an alternative to registering
all GOs and GOPs as TOs and TOPs, a strategy that has been widely supported by the stakeholder body. The SDT does agree that upon
interconnection of a third party, other standards or registrations may apply as appropriate.
Southwest Power Pool
Regional Entity
No
The Technical Justification document did not review the standards FERC identified in
paragraphs 71 and 87 of 135 FERC ¶ 61,241 ORDER DENYING APPEALS OF ELECTRIC
RELIABILITY ORGANIZATION REGISTRATION DETERMINATIONS. The SDT needs to
review these standards to determine if changes are needed; otherwise, FERC will
require registration of GOs and GOPs as TOs and TOPs to address reliability gaps. If
the SDT determines no changes are needed to these FERC-identified standards, they
should provide justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives) within the standards process. However, based on your and other comments, we have
expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards,
the SDT continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP
requirements to these standards.
Southern Company
No
We don’t believe the effort realizes the goal because 1) it is inclusive of FAC-001 that
does not need any modifications and 2) the effort needs to reinforce the appropriate
justification not to include the additional standards FERC has identified in their Cedar
Creek and Milford Orders.
Response: The SDT thanks you for your comment. The SDT believes that comment (1) is a complex issue and did its best to outline
how it arrived at its position in the document titled “Technical Justification: FAC-001-1.”
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Question 7 Comment
As for comment (2), the NERC Standard Processes Manual does not address the issue of how to deal with FERC Orders (that don’t
include explicit directives) within the standards process. However, based on your and other comments, we have expanded our
technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
Western Electricity
Coordinating Council
No
WECC casts an affirmative vote for the SDT proposal as a necessary but not sufficient
step in addressing the GOTO matter. WECC, NERC, and the other Regions developed
a subset of Standards and Requirements that were considered necessary to address
potential gaps for transmission interconnection facilities and operations to be
included in a proposed NERC Directive, which is expected to issue by year-end. The
subset of requirements developed for the proposed NERC Directive were informed by
the applicable FERC Orders. Consequently, it is important that the SDT address the
comparative reliability risks between the proposed NERC Directive List and the SDT
Proposal to assure that reliability gaps will not result from the SDT proposal. Please
see NERC’s proposed Directive for the rationale and technical justification.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives), or NERC directives, within the standards process, and until this round of comments,
when NERC staff submitted comments, the SDT had no formal mandate that would have made it appropriate to consider the content
of the directive you reference.
However, based on your and other comments, we have expanded our technical justification document (posted under “Supporting
Materials”) to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance
directive. After another thorough review of these standards, the SDT continues to believe that there are clear and technical reliabilitybased reasons that support not adding GO and GOP requirements to these standards.
Florida Municipal Power
Agency
FMPA believes that TOP-004-2 R6.2 ought to also be addressed in the standards as
applicable to GOPs. The requirements reads:R6. Transmission Operators, individually
and jointly with other Transmission Operators, shall develop, maintain, and
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Question 7 Comment
implement formal policies and procedures to provide for transmission reliability.
These policies and procedures shall address the execution and coordination of
activities that impact inter- and intra-Regional reliability, including:R6.2. Switching
transmission elements.Although planned outages are covered in other standards
applicable to a GOP, switching to close / synchronize a generator back to the system is
not specifically covered in the standards. Some have argued that TOP-002-2 R3 causes
GOPs to coordinate its current day plans with the TOP; however, the name of the
standard is “Transmission Operations Planning” and therefore implies the availability
of the generator and related equipment and not necessary implies the policies and
procedures for switching operations; which includes synchronization. FMPA cannot
imagine a generator that would not have such switching / synchronization policies
and procedures coordinated with its interconnecting TOP; as such would normally be
required through a Large Generator Interconnection Agreement through a pro forma
OATT; however, FMPA is not aware of any instance in the standards that covers this.
As such, FMPA recommends including TOP-004-2 R6.2 as being applicable to a GOP.
Response: Thank you for your comment. We don’t agree that the gap exists because TOP-002-2 R3 already requires the GO to
coordinate with its host BA and TSP, who in turn are required to coordinate with their TOPs.
Manitoba Hydro
If the redline changes are implemented, GOs are removed from R4, thereby removing
the obligation for GOs to maintain their connection requirements. If GOs are included
in FAC-001, they should be held accountable to the same level as TOs and should be
required to maintain their connection requirements. Requiring a GO to maintain
connection requirements would be especially beneficial to the GO themselves. In the
majority of instances, any GO that is an Applicable Entity for FAC-001 would initially
be inexperienced in performing interconnection studies and would benefit from
regular and frequent review of their connection requirements as experience and
expertise are gained.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
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Question 7 Comment
in the document titled “Technical Justification: FAC-001-1.”
SERC OC Standards Review
Group
Please list the set of standards are you referencing.
Response: The SDT is referring to those standards posted for comment (FAC-001-1, FAC-003-X, FAC-003-3, and PRC-004-2.1).
Constellation Power Source
Generation, Inc.
Affirmative
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. Please see more detailed comments submitted in the Project 201007 comment form submitted on November 18, 2011.
Response: Thank you for your comment and support.
Infigen Energy US
Affirmative
Infigen finds the SDT supporting measures and analysis regarding FAC-003-3 to be
appropriate, and believes that it is prudent for Generation Owners and Transmission
Owners to manage vegetation maintenance records/inspections accordingly. We
support maintaining "reasonable and appropriate" risk prevention measures to
minimize encroachment that could trigger vegetation-related outages.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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Question 7 Comment
significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
Affirmative
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
The SDT agrees with your comment regarding the language in the Data Retention section and has modified that section as follows:
“The Transmission Owner, and Distribution Provider that own a transmission Protection System and the Generator Owner that owns a
generation or generator interconnection Protection System…”
Southwest Transmission
Cooperative, Inc. / ACES
Power Marketing
Affirmative
We largely support the changes made by drafting team because we believe the
drafting team has provided the best solution in face of a difficult problem. However,
in general, we do not support registration of GOs and GOPs as TOs and TOPs or
applicability of any TO/TOP requirements to the GO/GOP simply because they have a
radial interconnection greater than one mile in length. While there may be some
generators that own interconnecting facilities of significant length operated at a
significant voltage that could impact BES reliability, we do not believe that the
number of generating facilities that fit into that category is significantly large. When
one considers that the majority of generators are still owned and operator by utilities
that are also registered as a TO and TOP, there is only a minority subset of generators
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left that could be considered. NERC has the registration for this remaining set of
generators and could use the data to evaluate how many of this remaining subset
have interconnections owned by the generator that are substantial enough to affect
reliability. It seems that NERC could determine the boundaries of this problem before
registering anymore GOs and GOPs as TOs and TOPs or before applying additional
requirements through this effort on the GOs and GOPs. Subjecting a GO/GOP to any
TO/TOP standards requirements should require a clear demonstration f the reliability
gap in each instance. Some additional changes are necessary to FAC-001.
Response: Thank you for your comment and support. We are unsure as to what changes to FAC-001 you feel are necessary unless you
are referring to comments stated previously.
Ingleside Cogeneration LP
(Occidental Chemical)
Yes
Although the SDT is nearing conclusion on the closing of reliability gaps, the
unnecessary registration of GOs and GOPs as TOs and TOPs is far from resolved in our
view. Ingleside Cogeneration’s concern is based upon NERC’s recent proposal to
dictate an interim GO-TO interconnection solution which completely bypasses the
Standards Development Process. Frankly, it seriously brings to question the nature of
the consensus-driven process - which appears to be moving in a dictatorial direction.
Response: Thank you for your comment and support.
American Wind Energy
Association
Yes
AWEA believes that the standards modifications proposed by the SDT should address
any genuine reliability gap with regard to generator lead lines, rather than just
perceived but unsupported threats. To that end, we support the approach that the
SDT appears to be taking of modifying a limited number of applicable standards so
that they apply to GO/GOP lead lines. In particular, we fully support the fact that the
SDT recognizes that GO/GOPs should not automatically be required to register as
TO/TOPs simply because of their ownership of generator lead lines. The SDT correctly
recognizes that such registration should be done based on a case-by-case
determination. As already noted, registering a GO/GOP as a TO/TOP may actually
decrease reliability.
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Question 7 Comment
Response: Thank you for your comment and support.
RES Americas Development
Yes
We believe that the standards modifications proposed by the SDT should address any
genuine reliability gap with regard to generator lead lines, rather than just perceived
but unsupported threats. To that end, we support the approach that the SDT appears
to be taking of modifying a limited number of applicable standards so that they apply
to GO/GOP lead lines. In particular, we fully support the fact that the SDT recognizes
that GO/GOPs should not automatically be required to register as TO/TOPs simply
because of their ownership of generator lead lines. The SDT correctly recognizes that
such registration should be done based on a case-by-case determination. As already
noted, registering a GO/GOP as a TO/TOP may actually decrease reliability.
Response: Thank you for your comment and support.
Southwest Power Pool
Standards Development Team
Yes
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
MRO NSRF
Yes
SERC Planning Standards
Subcommittee
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
ACES Power Marketing
Yes
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Organization
Yes or No
Question 7 Comment
Standards Collaborators
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
Ameren
Yes
American Transmission
Company
Yes
Sempra Generation
Yes
Xcel Energy
Yes
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Organization
Yes or No
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
Question 7 Comment
Puget Sound Energy, Inc.
Compliance & Responsbility
Organization
Bonneville Power
Administration
South Carolina Electric and
Gas
Consolidated Edison Co. of
NY, Inc.
Entergy Services
ReliabiltiyFirst
Tennessee Valley Authority
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8. If you answered “yes” to Question 7, are the modifications the SDT has made in this posting the appropriate ones?
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, commenters either offered their support or directed
the SDT to their comments on other questions in this report.
Organization
Yes or No
Ameren
No
Question 8 Comment
Please refre to our comments in reposnes to #3, #4, and #5 above.
Response: Please see the SDT’s responses to Questions 3, 4, and 5.
Texas Reliability Entity
No
See comment 6.
Response: Please see the SDT’s response to Question 6.
Ingleside Cogeneration LP
(Occidental Chemical)
No
See comments to questions 1 through 4.
Response: Please see the SDT’s responses to Questions 1-4.
SERC Planning Standards
Subcommittee
No
See our comments above for question # 3.
Response: Please see the SDT’s response to Question 3.
South Carolina Electric and
Gas
No
The modifications are appropriate with the exception noted in question #3.
Response: Please see the SDT’s response to Question 3.
ACES Power Marketing
No
The modifications are largely the appropriate ones with the exceptions we noted in Q1
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Standards Collaborators
Question 8 Comment
and Q10.
Response: Please see the SDT’s responses to Questions 1 and 10.
Southwest Power Pool
Standards Development Team
No
We agree that the standards being addressed are correct. See above comments.
There are some issues with the determination of which facilities are deemed BES since
ownership of what may be a BES facility may not always be by a Transmission Owner.
All relevant standards should apply to BES facilities regardless of ownership.
Response: Thank you for your comment.
PSEG
No
Response:
SERC OC Standards Review
Group
See comments on Question 7. If the standards referenced in question 7 are FAC-001,
FAC-003 and PRC-004, we would answer yes to this question.
Response: Thank you for your comment and support.
Southern Company
Yes
 The version history table is incorrect - change version 3 to version 2.1.  
Response: Thank you for your comment. We have made this change.
RES Americas Development/
American Wind Energy
Association
Yes
For the most, we agree that the SDT proposal strikes a reasonable balance and
provides the requisite level of clarity and certainty necessary for GO/GOPs to
understand their responsibilities and compliance requirements.
Response: Thank you for your comment and support.
MRO NSRF
Yes
The NSRF agrees if the drafting team incorporates as suggested improvements
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Question 8 Comment
Response: Thank you for your comment and support.
Northeast Power Coordinating
Council, Northeast Power
Coordinating Council
Yes
Dominion
Yes
PPL NERC Registered Affiliates
Yes
Electric Power Supply
Association
Yes
American Electric Power
Yes
BP Wind Energy North
America Inc.
Yes
Exelon
Yes
Seattle City Light
Yes
Independent Electricity
System Operator
Yes
Duke Energy
Yes
Oncor Electric Delivery
Company LLC
Yes
American Transmission
Yes
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Organization
Yes or No
Question 8 Comment
Company
Sempra Generation
Yes
Xcel Energy
Yes
Cowlitz County PUD
Yes
Constellation Power Source
Generation
Yes
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9. If you answered “no” to Question 7, what standards need to be added or removed to achieve the SDT’s goal? Please provide
technical justification for your answer.
Summary Consideration:
The SDT thanks all stakeholders who submitted comments. Few stakeholders suggested that standards need to be added
or removed to achieve the SDT’s goal.
One commenter pointed out that PRC-005-1a required the same kind of change made in the proposed PRC-004-2.1a to
ensure that generator interconnection Facility Protection Systems are included within that standard. The SDT agrees with
this suggestion and has initiated a process to modify R1 and R2 in PRC-005-1a.
A few commenters returned to FAC-001-1 and stated their concern about the feasibility of adding FAC-001-1 to the
applicability section of this standard. The SDT agrees with commenters that the issues surrounding the interconnection of
a third party Facility to a GO’s existing Facilities are complex ones, and reminded commenters that it did its best to
address these complexities in the resource document titled “Technical Justification: FAC-001-1.” The SDT also points out
that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or indirectly
with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro
forma interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any
studies with an affected system which could include Facilities owned by one, or more, TO on the other side of the GO’s
existing point of interconnection. The SDT acknowledges that upon interconnection of a third party, other standards or
registrations may apply as appropriate.
Some commenters suggested that the SDT reexamine the standards cited in the Milford and Cedar Creek FERC orders.
The SDT continues to find clear and technical reliability-based reasons that support not adding GO and GOP requirements
to these standards and not requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern,
the SDT has expanded its technical justification document (posted under “Supporting Materials”) to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 9 Comment
Cowlitz County PUD
No
N/A
Manitoba Hydro
No
See question 7 comments.
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Question 9 Comment
Response: See the SDT’s response to Question 7.
Southern Company
Yes
Southern does not think that the revision to FAC-001-1 is necessary. A Generator
Owner (GO) cannot assess reliability impacts to the Bulk Electric System (BES) and
determine acceptability without support and involvement of the applicable owner and
operator of the Transmission System (i.e., the “interconnected TO” or “interconnected
TP”). A generator tie-line does not equate to a Transmission System. A GO must
already adhere to a TO’s Facility connection requirements whether the GO wants to
connect additional facilities or a third parties’ facilities to its own interconnection
Facilities. Stated another way, the GO does not need Facility Connection
requirements to govern how multiple units are tied to a collector bus so why are they
needed for a third party to connect to an existing tie-line? In either case it is the
interconnected TO or interconnected TP that has connection requirements that must
be fulfilled. The GO’s Interconnection Agreement would prohibit it from connecting
additional facilities without a new application for Interconnection Service with its
interconnected TO or interconnected TP. A GO should not need to develop
“connection requirements” unless it is in the business of owning and operating
facilities independently of its interconnected TO or interconnected TP. We do not
believe a reliability gap exists in FAC-001-1 because the requestor for interconnecting
another Facility to an existing generation Facility must coordinate with the applicable
TO, TP, and PA in accordance with FAC-002-0 to ensure they meet all applicable facility
connection and performance requirements. If and when there is an agreement in
place for a third party to connect to a generator tie-line then the tie-line would
become part of the integrated system and its purpose and the owner’s function would
likely warrant registration as a TO/TOP and FAC-001 would then apply. The following
excerpt from the 2010-07 Background Resource White Paper acknowledges that this
may be necessary: “The drafting team also acknowledges that, if another party
interconnects to a Facility owned by a Generator Owner, there may be the need to
address MOD or TPL standards. However, the drafting team believes that this, too, is
best handled through specific evaluation, perhaps accompanied by changes to the
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compliance registry. Entities that face this kind of scenario may also meet criteria
applicable to other registrations such as Transmission Service Provider or Transmission
Planner.” [Arguments related to jurisdictional, interconnection policy and open access
transmission tariff issues](1) Because of (a) jurisdiction under Section 215, (b) FERC’s
interconnection policy, and (c) the requirements of the pro forma open access
transmission tariff (OATT), a GO should not be required to comply with FAC-001-1
until that GO’s generating Facility reaches commercial operation. NERC should not
make facilities subject to the mandatory reliability standards before the facilities are
actually part of the BES.(a) Jurisdiction under FPA Section 215. First, it is not clear
that NERC or FERC has jurisdiction under FPA Section 215 to require generation
facilities that have not actually reached commercial operation to be subject to
reliability standards. Section 215(a)(2) of the FPA defines the “Electric Reliability
Organization” as “the organization certified by the Commission ... the purpose of
which is to establish and enforce reliability standards for the bulk-power system,
subject to Commission review.” Further, (a)(3) provides that “The term ‘reliability
standard’ means a requirement, approved by the Commission under this section, to
provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities ... the design of
planned additions or modifications to such facilities to the extent necessary to provide
for reliable operation of the bulk-power system ....” Thus, under Section 215 NERC can
develop reliability standards that address requirements for existing bulk-power system
facilities (i.e., facilities that have reached “commercial operation”) and for the design
of planned additions or modifications. It is logical to interpret the phrase “design of
new facilities” as meaning that new facilities must be designed to comply with existing
reliability standards. However, it is not clear that this provision should be interpreted
as requiring that a generating facility that has not yet reached commercial operation
should be subject to reliability standards (including audit and penalties). Therefore,
the GO with the existing generation facilities should not be required to incorporate
the proposed generation facility into its Facility connection requirements before the
proposed generation facility is subject to NERC or FERC jurisdiction. (b) FERC’s
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Question 9 Comment
interconnection policy. In addition, the revised FAC-001 would appear to place
restrictions on interconnection customers in contravention of Order Nos. 2003 and
2006 (Standard Large and Small Interconnection Procedures and Agreements). FERC
was very concerned about the ability of interconnection customers to interconnect
their generating facilities and gave them a fair amount of flexibility. However, this
revised FAC-001 would appear to restrict some of this flexibility.(i) Order No. 2003
gives the interconnection customer the ability to terminate a proposed
interconnection on ninety days notice. Therefore, the interconnection customer is not
required to build the facility. However, this revised FAC-001 appears to assume that
the interconnection customer does not have this flexibility. What if the
interconnection customer (the GO building a new generator on its site or the third
party building a new generation facility) decides to terminate the Large Generator
Interconnection Agreement (LGIA) or not proceed with the generation facility? In such
event, the GO may be required to revert to its previous Facility connection
requirements in order to accommodate the original configuration. (ii) The LGIA
permits modifications to the proposed interconnection. How would this affect the
Facility connection requirements? How long would the GO have to revise its Facility
connection requirements? In the event that there is a single modification, or perhaps
multiple modifications, how does the GO stay in compliance with this standard? (iii)
FAC-001-1, R4 provides that each GO with Facility connection requirements and each
TO shall maintain Facility connection requirements and make documentation of these
requirements available to users of the Transmission System upon request. However,
Large Generator Interconnection Procedures (LGIP), Section 3.4 requires the posting
of certain interconnection information but the identity of the interconnection
customer is not to be disclosed (unless it is an Affiliate). Requirement R4 would
appear to potentially require disclosure of information and (more importantly) of the
interconnection customer's identity in contravention of the requirements in Order No.
2003 and the LGIP.(c) OATT requirements. The definition of “applicable Generator
Owner” (Section 4.2.1) and Requirement R2 provide that the GO will have an executed
Agreement to evaluate the impact of interconnecting a new facility to the GO’s
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Question 9 Comment
existing generation facility. This statement is ambiguous. This statement could be
understood to mean that the GO of the existing generation Facility will enter into an
Agreement with the GO proposing to interconnect and the existing GO will evaluate
the impact of the proposed interconnection. However, requests to interconnect new
generation are processed under an OATT. In that case, it would be the Transmission
Provider (not the existing GO) that would evaluate the impact of interconnecting the
new facility. Thus, the language in FAC-001-1 would need to be revised to clarify that
the owner of the new facility will need to interconnect under the OATT of an
appropriate Transmission Provider (i.e., the Transmission Provider to which the
existing GO is interconnected, not with the existing GO). Therefore, the owner of the
new facility will most likely be the entity with the executed Agreement (with the
Transmission Provider). Another consideration is that the existing GO could be
developing a merchant transmission line. In that case, the existing GO would need to
evaluate whether it needs have its own OATT and OASIS. In that case, the new
generator owner would be interconnecting to the existing GO. However, the existing
GO’s line would not be a generator tie-line. This issue is not clear from the draft
standard. (2) The following are suggested changes to FAC-001-1. (a) We recommend
the Purpose statement be revised to state, “To avoid adverse impacts on BES
reliability...” (b) It is unclear in Applicability section 4.2.1 that the term “Agreement”
means that the GO has an executed agreement with a TO/TSP or that the GO and the
third party have an executed agreement. Without further explanation, the capitalized
term “Agreement” has the effect of introducing confusion. If the SDT does not intend
to propose a new addition to the NERC Glossary of Terms, it should use the lower case
term, “agreement.” With respect to the capitalized term, “Transmission System,” the
SDT should consider clarifying if it intends to propose adding this to the Glossary. (3)
Effect of the proposed revisions to FAC-001-1 on FAC-002-1.(a) As drafted, there are
scenarios under which a new GO may attempt to interconnect to an existing GO even
though, as explained above, the interconnection should actually be done to the
appropriate Transmission Provider. If the appropriate Transmission Provider is not
included in the evaluation of the interconnection various types of harm may occur. In
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Question 9 Comment
such event, the TPs and PAs should be indemnified from any liability with respect to
performance of the evaluations required by FAC-002. (b) FAC-001 and FAC-002 should
be revised to be clear that the existing GO and any new GOs must coordinate any
interconnection with the appropriate Transmission Provider, TP and PA.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
The SDT points out that if the GO is part of an RTO, then the GO will be coordinating any interconnection studies either directly or
indirectly with the RTO interconnection process. If the GO is not part of an RTO, then the GO will be required to follow the pro forma
interconnection procedures from Order 2003. The Order 2003 procedures require the GO to coordinate any studies with an affected
system which could include Facilities owned by one, or more, TO on the other side of the GO’s existing point of interconnection.
The SDT does agree that upon interconnection of a third party, other standards or registrations may apply as appropriate.
PSEG
Yes
We believe that the Ad Hoc Group’s suggestions regarding PRC-005-1 - Transmission
and Generation Protection System Maintenance were correct and that this standard
should have been modified by the SDT in a manner similar to the way the SDT
modified PRC-004-2. This would require modifying R1 and R2 in PRC-005-1a (the
current version) to include protection systems in the generator interconnection
Facility. In addition, the SDT should evaluate modifying PER-002-0 - Operation
Personnel Training. In doing so the SDT completes one of the open FERC directives in
Order 693. Paragraph 1363 addresses GOP training:1363. Further, the Commission
agrees with MidAmerican, SDG&E and others that the experience and knowledge
required by transmission operators about Bulk-Power System operations goes well
beyond what is needed by generation operators; therefore, training for generator
operators need not be as extensive as that required for transmission operators.
Accordingly, the training requirements developed by the ERO should be tailored in
their scope, content and duration so as to be appropriate to generation operations
personnel and the objective of promoting system reliability. Thus, in addition to
modifying the Reliability Standard to identify generator operators as applicable
entities, we direct the ERO to develop specific Requirements addressing the scope,
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content and duration appropriate for generator operator personnel.
Response: Thank you for your comment. The SDT agrees with the comment concerning PRC-005-1a and will be initiating a process to
make that change.
With respect to PER-002-0, the SDT continues to find that there are no clear and technical reliability reasons that support adding GOP
requirements to any PER standard based on the fact that the GOP operates a generator interconnection Facility. While the SDT does
not necessarily disagree that some training requirements for GOPs may be necessary, it does not see how these changes fall within its
scope.
Ingleside Cogeneration LP
(Occidental Chemical)
Ingleside Cogeneration LP believes that the set of standards proposed by the SDT is
technologically accurate and defensible. The open issue is if the ERO and FERC expect
more standards to be included - whether based upon sound reliability principals or
not.
Response: Thank you for your comment and support.
Western Electricity
Coordinating Council
PLease see response to question #7.
Response: See the SDT’s response to Question 7.
Texas Reliability Entity
See comment 6.
Response: See the SDT’s response to Question 6.
SERC OC Standards Review
Group
See comments on Questions 7 & 8.
Response: See the SDT’s responses to Questions 7 and 8.
Florida Municipal Power
see response to Question 7
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Question 9 Comment
Agency
Response: See the SDT’s response to Questions 7.
Manitoba Hydro
The revision to FAC-001-1 R2 may be problematic, depending on what was intended.
Under the revised requirement, the obligation to comply is dependent on the
execution of an agreement to evaluate reliability impacts under FAC-002-1. However,
FAC-002-1 does not clearly require the execution of an agreement by the Generator
Owner. FAC-002-1 only requires the Generator Owner to “coordinate and cooperate
on its assessments with its Transmission Planner and Planning Authority”. Accordingly
if a Generator Owner coordinates without executing an agreement to perform an
assessment, compliance with FAC-001 R1 will not be required.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Southwest Power Pool
Regional Entity
The SDT should consider the standards that FERC identified in 135 FERC ¶ 61,241.
Response: Thank you for your comment. The NERC Standard Processes Manual does not address the issue of how to deal with FERC
Orders (that don’t include explicit directives). However, based on your and other comments, we have expanded our technical
justification document (posted under “Supporting Materials”) to include any standard or requirement cited by FERC in its
Milford/Cedar Creek orders or by NERC in its draft compliance directive. After another thorough review of these standards, the SDT
continues to believe that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to
these standards.
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10. Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all stakeholders for their comments. In this section, many stakeholders offered supportive comments.
Others offered a variety of suggestions, many of which were addressed.
One commenter suggested that the word “system” should not be capitalized in “Transmission System” in FAC-001-1
because the NERC glossary term “System” does not apply within the standard. The SDT agreed with this suggestion, and
changed all references to “Transmission System” to “interconnected Transmission systems” for consistency in other parts
of the standard and with FAC-002. Another commenter pointed out that “within” should be “with” in Section 4.2.1, and
the SDT made this change.
A few commenters repeated their concern with the exclusion in FAC-003 for GOs with specific kinds of interconnection
Facilities. For these commenters, the SDT reemphasized that in many cases, generation Facilities are either (1) staffed and
the overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have
generally supported the rationale exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines
that extend greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have
a clear line of sight from the switchyard fence to the point of interconnection and are…”.
Some stakeholders offered comments that were outside the scope of this SDT’s work. A few offered comments on the
overall strategy of the FAC-003-2 standard, and the SDT informed them that these comments should have been
submitted when the Project 2007-7 Vegetation Management posted its work for comment.
One commenter suggested changes to the VSLs for R1 and R4. Because the SDT made no changes to these requirements,
modifying the VSLs for these requirements is outside the scope of this team. This item will be added to the issues
database.
Several stakeholders suggested the SDT review the standards cited in the draft NERC directive regarding generator
interconnection leads and in the FERC orders regarding Milford and Cedar Creek. The SDT continues to find clear and
technical reliability-based reasons that support not adding GO and GOP requirements to these standards and not
requiring the GO or GOP to register as a TO or TOP. However, to address stakeholder concern, the SDT has expanded its
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technical justification document (posted under “Supporting Materials”) to include any standard or requirement cited by
FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive.
Organization
Yes or No
Question 10 Comment
Gainesville Regional Utilities
Negative
1. It would seem that the impetus for FAC003 is to eliminate vegetation related
outages within the rights-of-way as defined and subject to the exclusions as stated in
footnote
2. Thus the requirement is to manage the ROW to prevent vegetation related
sustained outages with the measure being no outages. With grow-ins and fall-ins from
within the defined ROW being controllable factors. 2. Including encroachments leaves
the door open for fines to be imposed with no actual outage(s) having occurred. This
may be like being found guilty of a crime that has not yet taken place.
3. Combine vegetation related sustained outages by “grow-ins” and “blowing
together of lines and vegetation located inside the ROW” as one item as they are both
consequences of the growth of vegetation either vertically and horizontally.
4. Leave vegetation related sustained outages by “fall-in” as a standalone as this will
be related to structural problems occurring from a variety of sources.
5. Combine R3 and R7 to R1 (development and implementation of a Transmission
Vegetation Management Plan which shall include documented maintenance
strategies or procedures or processes or specifications, delineation of an annual work
plan and completion of same). Thus this would be the competency based
requirements as a program without execution is meaningless.
6. R1 and R2 become R2 and R3.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and found that a response to this comment was provided. No change made.
Northern Indiana Public
Service Co.
Negative
Ballot needs work
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Question 10 Comment
Response: The SDT does not understand your specific concern.
PSEG Energy Resources &
Trade LLC, PSEG Fossil LLC,
Public Service Electric and Gas
Co.
Negative
FAC-003-X is not applicable since FAC-003-2 was approved by the BOT on November
4, 2011
Response: Thank you for your comment. You are correct that in November 2011, NERC’s Board of Trustees adopted FAC-003-2 –
Transmission Vegetation Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC
staff will file FAC-003-2 with the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both
FAC-003-3 (proposed changes to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1)
with the intention of eventually only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2
and FAC-003-3 are not approved by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity
responsible for managing vegetation on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
Hydro-Quebec TransEnergie
Negative
Hydro-Quebec TransEnergie is casting a negative vote again because our comment
from the last posting was not considered in the current draft: The minimum
frequency of Vegetation Inspection should be based upon an average growth rates of
smaller regions than all North America. Example, above the latitude of 50 degrees
North, the vegetation growth rates is limited. The Vegetation Inspection frequency in
the territories located above 50 degrees of latitude must be relaxed to 3 years.
Response: Thank you for your comment. This is outside the scope of the SAR for this project. This SDT did review comments
submitted as part of the Project 2007-07 effort and did not find this comment had been submitted as part of that project effort. No
changes made.
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Question 10 Comment
New Brunswick System
Operator
Negative
Since NBSO voted 'affirmative' for FAC-003-3, it makes sense for us to vote 'negative'
for this standard.
Response: Thank you for your comment. In November 2011, NERC’s Board of Trustees adopted FAC-003-2 – Transmission Vegetation
Management (developed under Project 2007-07 Vegetation Management). Based on this approval, NERC staff will file FAC-003-2 with
the applicable regulatory authorities. The Project 2010-07 SDT will move forward with ballots for both FAC-003-3 (proposed changes
to the BOT-adopted FAC-003-2) and FAC-003-X (proposed changes to the FERC-approved FAC-003-1) with the intention of eventually
only filing FAC-003-3. The SDT has elected to carry FAC-003-X through to ballot because if FAC-003-2 and FAC-003-3 are not approved
by FERC, the SDT wants to be ready to file FAC-003-X to ensure that there is a functional entity responsible for managing vegetation
on the piece of line commonly known as the generator interconnection Facility.
Note that for its recirculation ballot, the SDT will be balloting both FAC-003-3 and FAC-003-X, but stakeholders should not vote as
though they are choosing one or the other. As stated above, the SDT plans to present FAC-003-3 alone to NERC’s Board of Trustees,
but it wants to have FAC-003-X ready to submit to the Board if, for some reason, neither FAC-003-2 nor FAC-003-3 are approved by
FERC. Members of the ballot body should vote on the merits of each version of FAC-003 individually. In other words, stakeholders
who support adding GOs to the applicability of FAC-003 should vote in the affirmative for both FAC-003-3 and FAC-003-X.
PSEG Energy Resources &
Trade LLC/ Public Service
Electric and Gas Co./ PSEG
Fossil LLC
Negative
The phrase “generator Facility” should be “generator Transmission Facility,” and the
phrase “Transmission System” should be “Transmission system.”
Response: Thank you for your comment. We agree with your change to “Transmission system” but not to the addition of
“Transmission” in the phrase “generator Facility.” The SDT does not agree with labeling a GO’s Facility as “Transmission,” in part
because in some areas (like Texas), GOs, by statute, can’t own Transmission. It was also brought to the SDT’s attention that in most
cases, the Facility in question is referred to as the Interconnection Facility in documents filed by the GO with FERC. Therefore, the SDT
intentionally modified language so that a Facility owned by a generation entity did not contain the term “Transmission.”
SERC Reliability Corporation
Negative
There should not be a weak link under the standard. This proposed revision would
create a weak-link where a portion of the otherwise covered right-of-way would be
exposed.
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Question 10 Comment
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”.
New York State Department
of Public Service/ National
Association of Regulatory
Utility Commissioners
Negative
Understand that there is an open issue regarding the availablility of generation
compliance documentation that needs to be satisfactorily addressed.
Response: The SDT does not understand your specific concern.
Infigen Energy US
Affirmative
Infigen supports the efforts of the SDT to ensure that Protection System
Misoperations affecting the reliability of the BES are thoroughly analyzed and
mitigated. Generator Owners are already analyzing Misoperations as/if they occur,
and are employing Corrective Action Plans to avoid future Misoperations. We support
maintaining "reasonable and appropriate" preventative measures and risk assessment
tools to ensure that misoperations are evaluated and corrected expediently.
Response: Thank you for your comment and support.
PPL EnergyPlus LLC/PPL NERC
Registered Affiliates
Affirmative
PPL Generation, LLC, on behalf of its NERC-registered subsidiaries, appreciates the
effort by the Standard Development Team to address the GO-TO interface issues in a
manner that enhances the reliability of the BES without adding unnecessary burden
on Generators. As registered GOs/GOPs, the PPL Generation registered entities agree
with the changes made by the SDT to these three standards. To the extent that
GOs/GOPs are required to register as TOs/TOPs, PPL Generation would have
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significant concerns with meeting the compliance requirements applicable to TOs in
the standards included in the scope of this Project, as well as other TO/TOP
requirements throughout other NERC standards.
Response: Thank you for your comment and support.
SERC Reliability Corporation
Affirmative
The Generator Owner may be required to self-certify and report periodically to the
region whether they have become applicable to the standard.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc./ ACES Power
Marketing Standards
Collaborators/ ACES Power
Marketing
Affirmative
The modifications to PRC-004-2.1 R2 could be interpreted as requiring the GO to
analyze Protection System Misoperations on the generator interconnection Facility
even if it does not own the Facility. We suggest modifying the requirement as shown
below to address this issue.”The Generator Owner shall analyze Protection System
Misoperations on its generator and generator interconnection Facility that it owns ...”
Response: Thank you for your comment. The SDT believes that the language makes clear that an entity need only be concerned with
the Elements or Facilities that it owns.
SERC Reliability Corporation
Affirmative
With the understanding the Generator Interconnection FAcilities will be grouped with
Transmission Protection Systems for analysis at the regional level.
Response: Thank you for your comment and support.
Entergy Services
We suggest that the Vegetation Management Standards should be consistent for
both the TO and GO facilities. We would also like to suggest an additional
Recommendation for added clarity regarding Category 3 Outages (Off-ROW Fall-in
Outages). We understand that the Category 3 Outages are not a violation of the
Standard, but we feel that there should be some level of comment added within the
Standard clearly stating that these Outages are “Reportable Only” during the
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Quarterly Outage reports to the RE’s, and that there are no associated
violations/sanctions for this Category Of Outage, and that an Off-ROW fall-in outage
would not be considered an encroachment into the MVCD in any way. The Technical
Reference Document does a good job of clearly stating this in the Introduction on
Page 5 (“This standard is not intended to address outages such as those due to
vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human
activities or acts of nature.”) and we feel that this should also be stated clearly in the
Standard.
Response: Thank you for your comment. As it discusses in the document titled “Technical Justification Project 2010-07 Generator
Requirements at the Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are either (1) staffed and the
overhead portion is within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit. The SDT and industry
comments support the position that these qualifiers represent a reasonable and appropriate risk prevention approach.
To clarify the exemption, the SDT has modified 4.3.1 to include a reference to line of sight: “Overhead transmission lines that extend
greater than one mile (1.609 kilometers) beyond the fenced area of the generating switchyard or do not have a clear line of sight from
the switchyard fence to the point of interconnection and are…”.
The remainder of your comment is outside the scope of this SDT.
Southern Company
We agree with the 2010-17 Standard Drafting Team’s conclusion to not modify other
standards such as those mentioned on page 4 of the Technical Justification document.
In additon, we wish to provide the following support for exclusion of these specific
standards. Southern Company believes NERC’s Project 2010-07 SDT must challenge
making revisions to the standards included in the FERC order on Cedar Creek and
Milford. (This order supports NERC’s requirement for those entities to register as a
TO/TOP due to their ownership of generator interconnection circuits > 100kV.) We
believe there are clear technical and reliability-based reasons that support not adding
GO and GOP requirements to these standards and not requiring the GO or GOP to
register as a TO or TOP. Furthermore, we also believe there are clear distinctions
between GO/GOP responsibilities and TO/TOP responsibilities that must be
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maintained to ensure BES reliability. Revising standards to assign TO/TOP
responsibilities to a GO/GOP or requiring a GO/GOP to register as a TO/TOP because
of generator interconnection circuits > 100kV will reduce the clarity of these
responsibilities. We have provided specific comments on each standard below:
EOP-005-1 R1, R2, R6, R7R1 and R2 require each TOP to have and maintain a system
restoration plan. R6 requires the TOP to train its operating personnel in
implementing this plan. R7 requires the TOP to verify its restoration plan by actual
testing or simulation. These requirements are clearly the role and responsibility of
the TOP, not a GO/GOP who happens to have generator interconnection facilities in
the TOP’s control area. The GOP’s roles and responsibilities are clearly and
appropriately addressed EOP-005-2. The presence of a generator interconnection
circuit > 100kV that happens to be owned by the GO instead of the TOP
fundamentally does not change the roles and responsibilities of the TOP or the GOP.
Thus, no changes due to EOP-005 are needed.
FAC-014-2, R2: FAC-014-2 R2 states “The Transmission Operator shall establish SOLs
(as directed by its Reliability Coordinator) for its portion of the Reliability Coordinator
Area that are consistent with its Reliability Coordinator’s SOL Methodology.” FAC014-2 R2 should not be revised to include GOPs. The GO is required by FAC-008-1 R1
and FAC-009-1 (FERC approved version) and pending FAC-008-3 R3 and R6 (FAC-008-3
filed with FERC for approval) to document the Facility Ratings for a GO-owned
generator interconnection circuit >100kV. The established Facility Rating must
respect the most limiting applicable equipment rating in the circuit and must consider
operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the GO to
the GOP if they are not the same entity. The operating voltage limits for this circuit
are established by the applicable TO/TOP, not the GO or GOP. Therefore, we believe
adding the GO to FAC-014-2 R2 would be redundant.
PER-003-1 R2, R2.1, R2.2PER-003-1 R2 and its sub-requirements state:”R2. Each
Transmission Operator shall staff its Real-time operating positions performing
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Transmission Operator reliability-related tasks with System Operators who have
demonstrated minimum competency in the areas listed by obtaining and maintaining
one of the following valid NERC certificates (1 ) : [Risk Factor: High][Time Horizon:
Real-time Operations]: R2.1. Areas of Competency R2.1.1. Transmission operations
R2.1.2. Emergency preparedness and operations R2.1.3. System operations R2.1.4.
Protection and control R2.1.5. Voltage and reactive R2.2. Certificates o Reliability
Operator o Balancing, Interchange and Transmission Operator o Transmission
Operator This requirement is specifically for TOPs. Personnel training for GOPs needs
to be addressed separately and not mingled with responsibilities of the TOP. The
GOPs role in supporting BES reliability needs to be clearly understood and defined
prior to establishing training requirements in the standards.
PRC-001-1, R2, R2.2, R4, R6Generator Operators (GOPs) and the scope of protection
equipment for generation interconnection Facilities are already appropriately
accounted for in this standard in requirement R2 and sub-requirement R2.2 The
language used in requirement R2 which applies to the GOP uses the general terms
“relay or equipment failures” which would include not only generator relaying, but
generator interconnection relaying in the GOPs scope as well. The GOP is required to
notify the TOP and Host BA in R2.1 “if a protective relay or equipment failure reduces
system reliability.” Requirement R2.2 requires the affected TOP to notify its RC and
affected TOPs and BAs. Thus, applying R2.2 to a GOP would be redundant to R2.1.
Requirement R4 states, “Each Transmission Operator shall coordinate protection
systems on major transmission lines and interconnections with neighboring
Generator Operators, Transmission Operators, and Balancing Authorities.” A
generator interconnection tie line does not constitute a ‘major tie line” or major
“interconnection with neighboring GOPs, TOPs, and BAs.” Thus, R4 should not be
revised to include GOPs. If a GO exists within NERC that does own such
interconnection facilities, the responsibility for coordination of protection systems on
such a line or interconnection should be the responsibility of the TOP in that area, not
the GO/GOP. This may require formal agreements between the TO/TOP and GO/GOP,
since the GO may own protection equipment on his end. The same logic applies to
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R6. R6 states, “Each Transmission Operator and Balancing Authority shall monitor the
status of each Special Protection System in their area, and shall notify affected
Transmission Operators and Balancing Authorities of each change in status.” This is
clearly the responsibility of the TOP and/or BA, not a GO/GOP who happens to have
generator interconnection facilities in the area. An SPS function by definition is to
maintain BES reliability. If a GO/GOP has equipment within the equipment scope of a
Special Protection System (SPS), responsibility for monitoring the SPS should be
conveyed in a formal agreement as appropriate.
TOP-001-1 R1Requirement R1 states, “Each Transmission Operator shall have the
responsibility and clear decision-making authority to take whatever actions are
needed to ensure the reliability of its area and shall exercise specific authority to
alleviate operating emergencies.” This is clearly the responsibility of the TOP, not a
GO/GOP who happens to have generator interconnection facilities in the TOP’s area.
Thus, R1 should not be applied to a GO/GOP who owns or operates generator
interconnection facilities. Furthermore, TOP-001-1 R3 (proposed to be covered in the
future in the proposed IRO-001-2 R2 and R3) appropriately requires the GOP to
comply with reliability directives issued by the TO “unless such actions would violate
safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the TOP the necessary decision-making authority over operation of all
generator Facilities up to the point of interconnection. They also give the GOP the
necessary authority to take appropriate actions to ensure safety and protection of the
GO’s equipment. Thus, no changes to TOP-001-1 are necessary.
TOP-004-2 R6, R6.1, R6.2, R6.3, R6.4Requirement R6 and its sub-requirements state:
“R6. Transmission Operators, individually and jointly with other Transmission
Operators, shall develop, maintain, and implement formal policies and procedures to
provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional
reliability, including:R6.1. Monitoring and controlling voltage levels and real and
reactive power flows.R6.2. Switching transmission elements.R6.3. Planned outages of
transmission elements.R6.4. Responding to IROL and SOL violations.”These are clearly
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the responsibility of the TOP, not a GO/GOP who happens to have generator
interconnection facilities in the TOP’s area. Thus, these requirements should not be
applied to a GO/GOP who owns or operates generator interconnection facilities. The
same logic applies here as stated above in our discussion on TOP-001-1. We believe it
is inappropriate and would be adverse to BES reliability to apply these requirements
to a GOP. TOP-004-2 effectively gives the TOP the necessary decision-making
authority over operation of all generator Facilities up to the point of interconnection.
They also give the GOP the necessary authority to take appropriate actions to ensure
safety and protection of the GO’s equipment, such as opening high voltage generator
output breakers when required to protect the unit. Thus, no changes to TOP-004-2
are necessary.TOP-006-2 R3Requirement R3 states, “R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall provide appropriate technical
information concerning protective relays to their operating personnel. The intent of
this requirement when applied to a GOP is already addressed in PRC-001-1 R1 which
states, “Each Transmission Operator, Balancing Authority, and Generator Operator
shall be familiar with the purpose and limitations of protection system schemes
applied in its area.” Thus, no change to TOP-006-2 is necessary.   
Response: Thank you for your comment and support. We agree that there are clear and technical reliability-based reasons that
support not adding GO and GOP requirements to these standards and not requiring the GO or GOP to register as a TO or TOP. We
have expanded our technical justification document (posted under “Supporting Materials”) to include any standard or requirement
cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and many of your explanations are
included therein.
American Wind Energy
Association
AWEA appreciates the opportunity to submit these comments on the NERC Project
2010-07. AWEA supports the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
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would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. AWEA supports the intent and goal of the SDT to ensure
that all generator-owned Facilities are appropriately covered under NERC’s Reliability
Standards. We also agree with the SDT that while many GO/GOPs operate Elements
and Facilities that might be considered by some entities to be Transmission, these are
most often radial Facilities that are not part of the integrated grid, and as such should
not be subject to the same standards applicable to TO/TOPs, who own and operate
Transmission Elements and Facilities that are part of the integrated grid. Therefore,
we support the SDT’s approach of identifying a very limited number of TO/TOP
standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP owners
of generator lead lines. We would be concerned, however, if additional requirements
were added beyond FAC-001, FAC-003, and PRC-004. Consideration of any additional
standards with respect to generator lead lines should be done on a standard-bystandard basis, reviewing the applicability of each standard as well as the impact on
the reliability of the Bulk Electric System.
Response: Thank you for your comment and support.
Bonneville Power
Administration
BPA thanks you for the opportunity to comment on Project 2010-07, Generator
Requirements at the Transmission Interface. BPA stands in support of the proposed
revisions and has no comments or concerns at this time.
Response: Thank you for your comment and support.
Constellation Power Source
Generation
Constellation appreciates and supports the work of the standard drafting team. We
recognize the significant time invested by technical experts from industry to consider
the appropriate application of reliability standards to address concerns raised about
coverage of transmission at the generator interface. The drafting team analysis
identified the standards in need of revision to appropriately address the reliability
concerns raised. While the revision process focuses on specific standards, it is
important to consider the reliability questions in the context of the full complement
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of reliability standards that apply to entities. For instance, the following standards
already apply to generators and relate to the reliability considerations around
transmission at the generator interface:
o PRC-001-1 addresses coordination of protection system components by requiring all
GOs to ensure coordination of their protection system with interconnected parties.
Further, FAC-002 requires that all new facilities undergo reviews by the TOP, BA, etc.
o PRC-004-1 requires all GOs to ensure that they analyze all misoperations on their
protection system which would include the protection of the tie line.
o TOP standards applicable to GOs aid coordination between a GO and a TO with
regards to the generator tie line by requiring all GOs to coordinate all maintenance
and emergency outages (both forced and planned) with all applicable interconnected
parties. Further, all ISO procedures require the same of GOs.
o RC, TOP and/or BA certified operators control and are responsible for overseeing
that transmission. According to the NERC functional model, a Generator Operator is
defined as “operat(ing) generating unit(s) and perform(ing) the functions of supplying
energy and reliability related services.” Given this limited scope, the Generator
Operator (GOP) cannot be considered as operating on the same level as the Reliability
Coordinator, Transmission Operator or Balancing Authority when it comes to real
time information on the status of the BES. The GOP does not monitor and control the
BES, rather the GOP only monitors and controls the generators that it operates and
relays information to other operating entities.
o IRO and TOP standards applicable to GOs include tie lines in their pool of resources
to alleviate operational emergencies by requiring all GOs to operate as directed by
their TOP, BA, or RC as directed and must render emergency assistance.
o FAC-8 and FAC-9 manage rating methodology consistency by requiring all GOs to
develop a methodology to rate all equipment, and that the RC has the authority to
challenge the GO on that methodology. The onus is on the GO to either change their
methodology and rating accordingly, or provide a technical justification as to why
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they cannot adopt the changes. Further, a generator will never be limited by its tie
line, as a generator’s profits are directly tied to its output. Therefore no generator
would limit its facility to the equipment that is delivering that output.
Response: Thank you for your comment and support. We agree that it is important to consider the reliability questions in the context
of the full complement of reliability standards, and we have endeavored to make these broader connections clear in our revised
technical justification document (posted under “Supporting Materials”). That document has been expanded to include any standard
or requirement cited by FERC in its Milford/Cedar Creek orders or by NERC in its draft compliance directive, and the kinds of further
justifications you also provided are included therein. After another thorough review of these standards, the SDT continues to believe
that there are clear and technical reliability-based reasons that support not adding GO and GOP requirements to these standards.
Cowlitz County PUD
In answer to the SDT request for feedback on FERC's Order concerning Cedar Creek
and Milford, the District finds no technical reason to add any of the listed standard
requirements, and struggles to understand why FERC would even consider this listing
as applicable.
Response: Thank you for your comment and support.
Southwest Transmission
Cooperative, Inc.
In section 4.2.1 of the Applicability Section, “within” should be “with”. Because
NERC’s Glossary of Terms establishes that an Agreement can be verbal and not
enforceable by law, section 4.2.1 should be further modified to clarify that it is a
legally enforceable and fully executed Agreement. The language in R3 in parenthesis
after Generation Owner should be modified to “once required by Requirement R2”.
This makes it clearer that R3 does not apply until the GO has an executed Agreement
to evaluate a request by a third part to interconnect.
Response: Thank you for your comment. We agree that “within” should be “with.” The SDT chose not to adopt the second
recommendation as the requirement already contains the term “executed.” The SDT also chose not to adopt the third
recommendation as the requirement already contains the parenthetical (in accordance with Requirement R2) which we feel is
synonymous with the comment.
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Yes or No
Manitoba Hydro
Question 10 Comment
Manitoba Hydro would also like to point out that if the redline changes are
implemented, it will greatly increase the complexity of coordination required under
FAC-002-1 for Transmission Planners/Planning Authorities.
Response: Thank you for your comment. The SDT agrees this is a complex issue and did its best to outline how it arrived at its position
in the document titled “Technical Justification: FAC-001-1.”
Compliance & Responsbility
Organization
NextEra Energy, Inc. (NextEra) appreciates the work of the Project 2010-07 Generator
Requirements at the Transmission Interface Standard Drafting Team (SDT) on a
subject that NextEra has a significant interest in resolving. In fact, NextEra has been a
member of the SDT and an active observer. Given the recent events - such as (a) the
North American Electric Reliability Commission's draft interim directive; (b) the denial
of the Milford and Cedar Cheek requests for reconsideration at the Federal Energy
Regulatory Commission (FERC) and (c) the record in this case which, at times, suggests
the SDT needs to more formally consider the Milford and Cedar Cheek Reliability
Standards - NextEra requests that SDT more formally consider the merits of each
Reliability Standard adopted the Milford and Cedar Cheek FERC orders and the NERC
draft interim directive. Although NextEra does not condone the manner in which
NERC issued the interim draft directive and stated so in its comments to NERC on the
interim draft directive, NextEra’s overarching objective on this issue is to bring a
uniform, fair and technically supported approach that resolves the interface issue.
Thus, NextEra requests that the SDT (prior to proceeding any further or any additional
comments or votes on specific draft Reliability Standards) issue a technical paper that
point-by-point addresses the merits of including the Reliability Standards set forth in
the FERC Orders and NERC’s draft interim directive, and request stakeholder,
including NERC staff, comment. For example, this technical paper would likely the
merits of NERC’s draft interim directive not requiring NERC-certified operators (but
require training of interface operators), while FERC’s orders require NERC-certified
operators. While NextEra does not agree five days of training is necessary for an
interface operator, as the draft interim directive appears to propose, NextEra does
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
115
Organization
Yes or No
Question 10 Comment
believe a technical case can be made why NERC-certification is not required, and that
some degree of training related to the applicable Reliability Standards is reasonable.
Similar, on FAC-003 (as well as several other Standards), the draft interim directive
proposes a slightly different approach than the SDT. NextEra would rather these
approaches reconciled than be in conflict, with the potential for continued conflict as
the SDT’s work product proceeds. Further, NextEra requests that the SDT’s review
the technical merits of NERC’s proposed criteria to determine what generator
transmission lead is required to comply with additional Reliability Standards. As
noted, above, this technical paper should be posted for stakeholder, including NERC
staff, comment. Accordingly, while NextEra would have preferred that NERC and the
Regional Entities express there interim draft directive approach on the record in this
proceeding, NextEra believes it is appropriate for the SDT to draft a comprehensive
technical paper that, with an open approach, considers the inclusion of additional
Reliability Standards, if appropriate, as a way of building lasting support for its
approach.
Response: Thank you for your comment and support. We certainly agree that is important for NERC staff and the SDT to continue to
work together to try to develop a mutually agreed upon solution for dealing with this reliability gap, and to a certain extent, the SDT
has tried to provide the kind of technical paper you suggest in its modified technical justification document (posted under “Supporting
Materials”), which has been expanded to include any standard or requirement cited by FERC in its Milford/Cedar Creek orders or by
NERC in its draft compliance directive. The SDT does not, at this point, plan to develop a technical paper that discusses the merits of
the standards introduced by FERC and NERC, because its current focus is on filing the FAC-001-1, FAC-003-3, and PRC-004-2.1a with
FERC. As it moves forward to a final solution, however, this kind of technical paper may prove useful. We appreciate the suggestion.
Dominion
No
Tennessee Valley Authority
No
Exelon
PRC-004 - suggest that the Standard state that responsibility for the analysis of
missoperations of protective equipment shall be the responsibility of the owner of the
protective equipment.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
116
Organization
Yes or No
Question 10 Comment
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
ReliabiltiyFirst
ReliabilityFist has found a number of editiorial erros for the FAC-001-1 VSLs. They
include the following:1. VSL R1 - should not reference sub-requirements, should
reference the sub-parts consistent with the requirement (i.e. Requirement R1, Part
1.1, 1.2 or 1.3) 2. VSL for R3 - the VSL should referenced Requirement 3, Part 3.1.1
through 3.1.16 rather than what is currently stated (Requirement R3, Part 3.1.1
R3.1.6)
Response: Thank you for your comment. While we agree that the VSLs for R1 need to be updated, that change is outside the scope of
this SDT because our changes are limited to those that incorporate the GO into the applicability of the requirement; the team made
no changes to R1 as it only includes the TO. We have, however, made the suggested changes to the VSLs for R3.
RES Americas Development
RES and AWEA appreciates the opportunity to submit these comments on the NERC
Project 2010-07. We support the general direction indicated by both the Generator
Requirements at the Transmission Interface Ad Hoc Group and the Project 2010-07
Standards Development Team. We agree with the sentiments from both groups that
a GO or GOP that also owns or operates a generator lead line should not be required
to register as a TO or TOP strictly because they own or operate a generator lead line.
We also agree that requiring these GO/GOPs to comply with all the TO/TOP standards
would have little effect on or benefits to reliability of the Bulk Electric System, and
could even detract from it. RES and AWEA supports the intent and goal of the SDT to
ensure that all generator-owned Facilities are appropriately covered under NERC’s
Reliability Standards. We also agree with the SDT that while many GO/GOPs operate
Elements and Facilities that might be considered by some entities to be Transmission,
these are most often radial Facilities that are not part of the integrated grid, and as
such should not be subject to the same standards applicable to TO/TOPs, who own
and operate Transmission Elements and Facilities that are part of the integrated grid.
Therefore, we support the SDT’s approach of identifying a very limited number of
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
117
Organization
Yes or No
Question 10 Comment
TO/TOP standards, such as FAC-001 and FAC-003, which should also apply to GO/GOP
owners of generator lead lines. We would be concerned, however, if additional
requirements were added beyond FAC-001, FAC-003, and PRC-004. Consideration of
any additional standards with respect to generator lead lines should be done on a
standard-by-standard basis, reviewing the applicability of each standard as well as the
impact on the reliability of the Bulk Electric System.
Sempra Generation
Sempra Generation also supports the comments, being concurrently filed, of the
Electric Power Supply Association (EPSA).
Response: Thank you for your comment and support.
Puget Sound Energy, Inc.
The changes to this standard are minor, and seem to be centered around including
"generator Interconnection facilities" to R2. This added phrase and the statement in
1.4 Data Retention "Generator Owner that owns a generation Protection System"
seems to assume that the generator owner and generator interconnection facilities
owner is always the same. This is not always the case, and will make this standard
language confusing to prepare evidence for. A suggestion would be to revise the
language to allow for a separate generator owner and generator interconnection
facilities owner.
Response: Thank you for your comment and support. The SDT believes that the language makes clear that an entity need only be
concerned with the Elements or Facilities that it owns.
SERC Planning Standards
Subcommittee/ SERC OC
Standards Review Group
The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”
Response: Thank you for your comment and support.
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
118
END OF REPORT
Consideration of Comments: Generator Requirements at the Transmission Interface
Project 2010-07
119
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission
Interface
Formal Comment Period Open March 9 – April 9, 2012
Successive Ballot Window Open March 30 – April 9, 2012
Available Now
The Generator Requirements at the Transmission Interface drafting team has posted limited revisions
to the Applicability sections of FAC-003-X—Transmission Vegetation Management Program and FAC003-3—Transmission Vegetation Management, along with implementation plans, for parallel formal
30-day comment periods and successive ballots.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy
of the comment form is posted on the project page.
Special Instructions for Submitting Comments with a Ballot
Please note that comments submitted during the formal comment period and ballot for the standard
all use the same electronic form, and it is NOT necessary for ballot pool members to submit more than
one set of comments. The drafting team requests that all stakeholders (ballot pool members as well as
other stakeholders) submit all comments through the electronic comment form.
Next Steps
Successive ballots of FAC-003-X and FAC-003-3 will begin on Friday, March 30, 2012 and will end at 8
p.m. Eastern on Monday, April 9, 2012.
Background
A Level 1 Appeal of FAC-003-3/FAC-003-X was received and reviewed by the Vice President of
Standards and Training and then the Standards Committee's Executive Committee. They determined
the appellant’s claim to be valid in part, and determined that the modifications the SDT made to the
applicability of FAC-003-3 and FAC-003-X prior to the recirculation ballot were substantive.
Consequently, the results of the recirculation ballots for FAC-003-3 and FAC-003-x have been declared
void. The Standards Committee's Executive Committee remanded FAC-003-3 and FAC-003-x to the SDT
with direction to consider the issues raised in the Exelon appeal and either:
•
•
Modify the language added following the initial ballot and then post the standard for a
successive ballot, or
Remove the language added following the initial ballot and go directly to recirculation
ballot.
A copy of the Executive Committee meeting minutes has been posted on the project page for
information.
The SDT reviewed FAC-003-X and FAC-003-3 again and modified them slightly. More detail is available
in the background section of the posted Unofficial Comment form, as well as in the updated
Considerations of Comments report.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying FAC-003 to Generator Owners as proposed in the redline standards posted for comment
supports this objective.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Announcement
Project 2010-07 - GOTO
2
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-07 - GOTO
3
Standards Announcement
Project 2010-07 – Generator Requirements at the Transmission Interface
Successive Ballot Results
Now Available
Ballots of two Generator Requirements at the Transmission Interface standards concluded Monday,
April 9, 2012:
• FAC-003-3 – Transmission Vegetation Management
•
FAC-003-X – Transmission Vegetation Management Program
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Standard
Quorum
Approval
FAC-003-3 – Transmission Vegetation Management
Quorum: 80.37%
Approval: 85.18%
FAC-003-X – Transmission Vegetation Management
Program
Quorum: 80.10%
Approval: 85.01%
Next Steps
The drafting team will consider all comments received during the formal comment period and
successive ballot. If the comments received during this formal comment period and ballot do not
indicate the need for significant changes, the drafting team will post its consideration of those
comments along with the standard and a recirculation ballot will be conducted.
Background
A Level 1 Appeal of FAC-003-3/FAC-003-X was received and reviewed by the Vice President of
Standards and Training and then the Standards Committee's Executive Committee. They determined
the appellant’s claim to be valid in part, and determined that the modifications the SDT made to the
applicability of FAC-003-3 and FAC-003-X prior to the recirculation ballot were substantive.
Consequently, the results of the recirculation ballots for FAC-003-3 and FAC-003-x have been declared
void. The Standards Committee's Executive Committee remanded FAC-003-3 and FAC-003-x to the SDT
with direction to consider the issues raised in the Exelon appeal and either:
• Modify the language added following the initial ballot and then post the standard for a
successive ballot, or
•
Remove the language added following the initial ballot and go directly to recirculation
ballot.
A copy of the Executive Committee meeting minutes has been posted on the project page for
information.
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying FAC-003 to Generator Owners as proposed in the redline standards posted for comment
supports this objective.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate. For more information or assistance, please contact Monica
Benson at monica.benson@nerc.net.
Ballot Results – Project 2007-09 | MOD-026-1 and PRC-024-1
2
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-x Successive Ballot March 2012_in
Password
Ballot Period: 3/30/2012 - 4/9/2012
Log in
Ballot Type: Initial
Total # Votes: 306
Register
Total Ballot Pool: 382
Quorum: 80.10 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.01 %
Vote:
Ballot Results: The drafting team is considering comments.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.8
1
1
1
1
0
0.4
0.1
0.7
7
#
Votes
Fraction
55
8
44
19
52
31
0
3
1
5
218
Negative
Fraction
0.887
0.8
0.8
0.864
0.839
0.861
0
0.3
0.1
0.5
5.951
Abstain
No
# Votes Vote
7
0
11
3
10
5
0
1
0
2
39
0.113
0
0.2
0.136
0.161
0.139
0
0.1
0
0.2
1.049
13
0
13
5
9
8
0
1
0
0
49
20
1
12
4
23
7
1
2
4
2
76
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
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Ballot
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
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View
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Dale Dunckel
Denise M Lietz
View
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
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Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0a88c83e-0ec8-4d89-ad0e-2488bfb51a42[4/11/2012 10:59:24 AM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
View
View
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Abstain
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Max Emrick
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Abstain
Abstain
Negative
View
Affirmative
Affirmative
Affirmative
Negative
View
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Affirmative
James Sauceda
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0a88c83e-0ec8-4d89-ad0e-2488bfb51a42[4/11/2012 10:59:24 AM]
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0a88c83e-0ec8-4d89-ad0e-2488bfb51a42[4/11/2012 10:59:24 AM]
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View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Affirmative
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
View
Affirmative
Affirmative
Affirmative
Peter H Kinney
David F. Lemmons
Frank R. McElvain
James A Maenner
Edward C Stein
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
View
Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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User Name
Ballot Results
Ballot Name: Project 2010-07 FAC-003-3 Successive Ballot March 2012_in
Password
Ballot Period: 3/30/2012 - 4/9/2012
Log in
Ballot Type: Initial
Total # Votes: 307
Register
Total Ballot Pool: 382
Quorum: 80.37 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
85.18 %
Vote:
Ballot Results: The drafting team is considering comments.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.8
1
1
1
1
0
0.4
0.1
0.7
7
#
Votes
Fraction
55
7
45
22
53
32
0
4
1
5
224
Negative
Fraction
0.873
0.7
0.804
0.88
0.841
0.865
0
0.4
0.1
0.5
5.963
Abstain
No
# Votes Vote
8
1
11
3
10
5
0
0
0
2
40
0.127
0.1
0.196
0.12
0.159
0.135
0
0
0
0.2
1.037
12
0
12
3
8
7
0
1
0
0
43
20
1
12
3
23
7
1
2
4
2
75
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d427147a-3df9-41c2-ad0e-d35d14b39830[4/11/2012 10:58:36 AM]
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Comments
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d427147a-3df9-41c2-ad0e-d35d14b39830[4/11/2012 10:58:36 AM]
View
View
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Dale Dunckel
Denise M Lietz
View
Affirmative
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
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3
3
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3
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3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
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4
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4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
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NERC Standards
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5
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5
5
5
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5
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5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
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John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
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Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
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Max Emrick
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
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Dana Showalter
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Stephen Ricker
John R Cashin
Affirmative
James Sauceda
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
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NERC Standards
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Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
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Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
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John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
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Peter H Kinney
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
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Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
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Individual or group. (23 Responses)
Name (16 Responses)
Organization (16 Responses)
Group Name (7 Responses)
Lead Contact (7 Responses)
Question 1 (22 Responses)
Question 1 Comments (23 Responses)
Individual
Brenda Frazer
Edison Mission Marketing & Trading
Yes
Individual
John Bee
Exelon
No
Exelon disagrees with the current proposed draft of FAC-003-3/X because the reference to a “clear
line of sight from the generating station switchyard fence to the point of interconnection” does not
clarify the Standard and is unsupported by any technical basis. Furthermore, the definition of “clear
line of sight” added by the SDT does not address or remedy the substantive concerns raised in
Exelon’s appeal. Exelon reiterates that the SDT should base the applicability of the Standard on the
length of the transmission line, a measurable component of the bulk electric system, and remove all
references to a “clear line of sight.” This approach is consistent with previous draft versions of FAC003 proposed by the SDT and the Ad Hoc Group and the recent recommendation of the NERC Vice
President of Standards and Training in response to Exelon’s appeal. Alternatively, if the “clear line of
sight” verbiage remains, the Standards should be clarified to remove the requirement that the line of
sight be established from “the generating station switchyard fence to the point of interconnection”
and to add a requirement or clarify that “clear line of sight” for lines of one mile or less can include
observation of the length of the transmission lines from various vantage points within the owner
controlled property. The SDT states in the “Background” section of the Unofficial Comment Form that
“a reference to the line of sight is clarifying and makes explicit the SDT’s implicit intent from day
one.” Yet, the SDT offers no support for its “implicit intent from day one,” and a review of the history
for these Standards certainly does not support an “implicit intent from day one” to require a clear line
of sight from a fixed location, let alone the generating station switchyard fence, to the point of
interconnection. The Technical Justification document posted in September 2011 (p. 3) refers to the
Ad Hoc Group’s original thought to exclude from the Standards any transmission lines that were “less
than two spans [long] (generally one half mile from the generator property line).” In agreeing “with
that intended exclusion in principle,” the SDT explained (p. 3) that, “[a]fter reviewing formal
comments, the SDT agreed to revise the exclusion so that it applies to a Facility [transmission line] if
its length is ‘one mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard’ to approximate line of sign [sic] from a fixed point,” (the fixed point being the fenced area
of the generating station switchyard). From the start, the Ad Hoc Group and SDT focused on the
length of the transmission line (either a half mile as proposed by the Ad Hoc Group or a mile as
proposed by the SDT) as the proxy for line of sight, the presumption being that up to a certain
distance, the overhead line is in the line of sight at various locations throughout the Generator
Owner’s property and reasonably subject to being managed through normal day-to-day plant
activities. The SDT has not, until the most recent iteration of the Standards, focused on requiring a
“clear line of sight from the generating station switchyard fence to the point of interconnection.” As
support for adding the “clear line of sight” requirement to the FAC-003-3/X Standards in December
2011, the SDT noted as follows: “We believe that the one mile length is a reasonable approximation
of line of sight, and that using a fixed starting point (at the fenced area of the generation station
switchyard) eliminates confusion and any discretion on the part of a Generator Owner or an auditor.”
With the addition of an explicit line of sight reference here, the SDT believes it has clarified its original
intent. (Side bar comments to FAC-003-3, Section 4.3.1 (December 1, 2011); FAC-003-X, Section
4.3.1 (December 1, 2011)). This explanation does nothing more than (1) reiterate the point the SDT
has maintained throughout the entire drafting process, namely that “the one mile length” of a
transmission line “is a reasonable approximation of line of sight,” and (2) explain that the SDT
included a “fixed starting point” (the fenced area of the generation station switchyard) from which to
measure the length of the transmission line to address stakeholder concerns about excessive
Generator Owner discretion with respect to the location from which to take a measurement and
inconsistent application of the Standards. Again, the SDT’s “intent” (implicit or otherwise) “from day
one” has nothing to do with establishing a “clear line of sight from the generating switchyard fence to
the point of interconnection.” In addition, requiring a “clear line of sight from the generating station
switchyard fence to the point of interconnection” is technically unsupported. The SDT just added the
requirement for a “clear line of sight to the point of interconnection” language without considering the
implications of why such a change was required or reasonable. While a specific fixed starting point
(the generating station switchyard fence) and end point (the point of interconnection) may make
sense for establishing a starting and ending point from which to measure the length of the
transmission line (the one-mile limitation), it does not make sense when considering a clear line of
sight, especially in light of stakeholder comments and the SDT’s repeated acknowledgment that in
many cases, generation Facilities are either (1) staffed and the overhead portion is within the line of
sight or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC-003 would offer no reliability
benefit. The SDT and industry comments support the position that these qualifiers represent a
reasonable and appropriate risk prevention approach. (Consideration of Comments, Generator
Requirements at the Transmission Interface, Project 2010-07 (for November 9, 2011 successive
ballot), p. 1; Technical Justification Resource Document (posted March 2012), p. 3.) By inserting the
“clear line of sight” requirement now without modifying the fixed starting point, the SDT completely
ignores its unequivocal acknowledgment that generation Facilities are unique in the sense that
personnel can see the line from various locations within the owner controlled area and many
generation Facilities are over paved surfaces. The absence of a technical justification for imposing a
“clear line of sight” is illustrated by the following example. A Generator Owner transmission line
leaving the generating station could take a ”dog leg” turn (the line turns at one of the towers).
Standing at the tower in this example, an individual would have a clear line of sight of the entire line
to either end of the short-distance line (to the end leaving the station and to the end terminating at
the point of interconnection). Since the generating Facility is within the Generator Owner’s property
line or controlled area and consistently staffed by personnel who patrol the owner controlled area, the
line can be observed and maintained by staff in the same manner as any other short distance line
with a “clear” line of sight from the “generating station switchyard fence to the point of
interconnection.” Moreover, to the extent a portion or the entire length of the line travels over paved
surfaces or structures, any barriers or obstacles to a clear line of sight will not be caused by
vegetation, as discussed in FAC-003-3/X but, rather, by equipment, components, or structures.
Clearance between generator lines and structures is already covered in other NERC Standards. For
those lines that do travel over areas of vegetation, the regular personnel monitoring and surveillance
of the areas over which the lines travel provides reasonable assurance of protection from vegetation
related events. Rather than clarifying the Standards, the SDT has introduced more ambiguity into the
Standards. The addition of the “generating station switchyard fence” as the point of reference for a
clear line of sight adds more confusion than it solves by introducing a variable that will be left to the
discretion of generator owner and an auditor. What is the definition of a “generating station
switchyard fence?” As Exelon noted in its Appeal and at least one other Registered Entity noted in its
Comments for the first successive ballot (Consideration of Comments posted March 2012, p. 38),
some generation facilities do not have generating switchyards or generating switchyard fences. A
requirement that there be a clear line of sight from the “generating switchyard fence” is meaningless
in cases where no such switchyard or fence exists. Is it the fence surrounding the generating unit or
is it meant to refer to the fence surrounding the Transmission Owner’s associated switchyard and
relay house? What if there are multiple physical fence lines between the generating unit and the point
of interconnection? In addition, by introducing a point of reference that is not a physical component or
measurable reference of the bulk electric system, what precludes the Generator Owner from
arbitrarily moving the fence line to avoid applicability? Also lacking in clarity is the addition of a
footnote defining “clear line of sight” to mean “the distance that can be seen by the average person
without special instrumentation (e.g., binoculars, telescope, spyglasses, etc.) on a clear day.”
Generation Owners will be left to determine what constitutes an “average person,” a “clear day,” and
“special instrumentation.” For all these reasons, Exelon requests that the SDT base the applicability of
the Standard on the length of the transmission line, a measurable component of the bulk electric
system, and remove all references to a “clear line of sight.” Alternatively, if the “clear line of sight”
verbiage remains, the Standards should be clarified to remove the requirement that the line of sight
be established from “the generating station switchyard fence to the point of interconnection” and to
add a requirement or clarify that “clear line of sight” for lines of one mile or less can include
observation of the length of the transmission lines from various vantage points within the owner
controlled property.
Individual
Ray Phillips
Alabama Municipal Electric Authority
Yes
Group
Northeast Power Coordinating Council
Guy Zito
No
The Applicability language used in FAC-003-X is different from that used in FAC-003-3. The language
used in FAC-003-X uses “and” in several places which leads to confusion and a probable “null” result,
whereas the language in FAC-003-3 is more straightforward and makes use of “or”. The FAC-003-3
applicability language should be used in FAC-003-X. The explanation of what is meant by line of sight
should be incorporated in the Applicability Section wording as standards, at NERC’s direction, are
supposed to be getting away from the use of footnotes.
Individual
Joe Petaski
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project 2010-07. If a Generator
Owner is required to register as a TO, all the Requirements applicable to a TO should apply. There is
no need to change specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions. For additional information, please see Manitoba Hydro's comments submitted
in the comment period ending November 18, 2011. Manitoba Hydro does not believe that the SDT
fully addressed our concerns in their responses to our comments in that commenting period.
Individual
Dan Roethemeyer
Dynegy
No
Using the switchyard fence is to restrictive. There could be to many different layouts to keep it fair for
all GO's. For example, there could be an obstruction if limited to standing at the existing switchyard
fence but if one were to move a short distance away (i.e. corner of GO's building) then it could be
possible to see both ends of the tie line. This would also meet the intent of the added language since
it is now within line of sight. I recommend deleting "switchyard fence". Also, in order to account for a
GO not being able to dictate what happens inside a TO's switchyard, I recommend adding "entry or"
between "of" and "interconnection".
Individual
Thad Ness
American Electric Power
Yes
Individual
John Seelke
Public Service Enterprise Group
Yes
Individual
Dale Fredrickson
Wisconsin Electric
No
We strongly oppose the addition of the “clear” line of sight criteria to the Applicability. The report of
the GOTO Task Force, as well as prior draft revisions to FAC-003, included a test based solely on
circuit length, which is sufficient in our view to assure that the BES is not at risk due to vegetation
issues on generator tie lines. The expansion to include short tie lines, including those entirely on the
Generator Owner’s property which may not meet the line of sight qualifier, has no benefit to
reliability. Rather, the expanded applicability and the requirement for a formal vegetation
management program in these cases will consume resources for compliance that are better used for
actual reliability improvements.
Group
Texas Reliability Entity
Don Jones
No
In FAC-003-X: 1. We appreciate that you took Regional Entity out of the Applicability section, but
there is still a Requirement (R4) that applies to the Regional Entity. Is that Requirement intended to
be enforceable against the Regional Entities? We suggest removing Requirement R4. 2. In Part D.1.1,
only the Regional Entity should be listed as Compliance Monitor, since the Regional Entity has been
removed as an Applicable entity. 3. In the Purpose section, update the reference to NERC (use
“Corporation” instead of “Council”), and capitalize “Rights-of-Way” since it is a defined term. 4. We
suggest that you spell out “Regional Entity” in Applicability part 4.2.1. 5. In the implementation plan,
the reference to “R3” should be corrected to “R1” in the following sentence: “In those jurisdictions
where no regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees adoption.” In FAC-003-3: 6. There is no
Compliance Monitor listed on page 17. At least the Regional Entity should be listed here. 7. In the
Severe VSL for R2, replace “Transmission Owner” with “responsible entity.” 8. In the Severe VSL for
R1 and R2, remove “active transmission line” before “ROW.” That phrase is confusing in the VSLs
because it does not appear in the requirements, and it is not clear whether it is intended to change
the requirements. 9. In Table 2 (Alternating Current – meters AND Direct Current) the footnote
references are wrong. We think they should be 9 and 10, rather than 7 and 8. 10. In Table 2 (Direct
Current), the column headings are wrong. Only the first column heading should refer to voltage. The
rest should refer to MVCD.
Individual
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Individual
Daniel Duff
Liberty Electric Power LLC
No
The "line of sight" should be removed. It opens up the entity to a finding of non-compliance if a
temporary blockage of line of sight should occur.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
No
While it is clear that the SDT is attempting to include those facilities owned by Generator Owners that
travel long distances down right-of-ways, the applicability section of FAC-003-X and FAC-003-3, as
written, require industrial complexes with cogeneration facilities to develop Transmission Vegetation
Management Programs for generator lead lines that are not exposed to vegetation. Industrial
cogeneration location is typically chosen based on the availability of fuel, need for steam, or
availability of real estate. This can result with the generation facilities (including the GSU transformer
substation) being located deep within the plant with long cable routes and multiple substation
connections between the GSU transformer substation and utility interconnection facility located near
the perimeter of the industrial complex’s fence line. Additionally, the routes of these generator lead
lines fundamentally differ in nature from a typical IPP’s generator lead line route. Since they are
located within the fence line of an industrial complex, the routes rarely contain vegetation; are
frequently travelled by plant personnel; rarely run in straight lines (i.e. no single line of sight); and
frequently terminate at a facility located at the fence line of the industrial complex where a
transmission company takes ownership of the power lines that leave the industrial complex.
Furthermore, the use of the term “generating station switchyard” may result in inconsistent
enforcement of the Transmission Vegetation Management Program Reliability Standard as the use of
the term implies there is only one substation located within a Generator Owner’s complex. Typically,
there are multiple substations that connect an industrial complex’s generator lead-line to the utility
interconnection facility located near the perimeter of the industrial complex’s fence line. The two
obvious interpretations for the “generating station switchyard” are the substation that is directly
connected to the generator’s GSU, and the utility interconnection facility. The concerns raised by
NERC and FERC staff related generator owned transmission like assets originate with those
conductors that leave the Generator Owner’s complex’s fence line and travel long distances down
vacant right-of-ways, and, therefore, the applicability of those Reliability Standards that apply to
transmission facilities should start with the fence line. Since the Bulk Electric System is contiguous,
reliability concerns related to the facilities between the GSU transformer substation and utility
interconnection facility are covered by those Reliability Standards that apply to Generator Owners and
Generator Operators. In order to account for the different nature of industrial complex’s generation
facilities, the SDT should consider re-phrasing the applicability section of FAC-003-X and FAC-003-3
to start counting the length of a generator lead line at the fence line of the Generator Owner’s
complex and not the generating station switchyard.
Individual
Brian Murphy
NextEra Energy, Inc.
No
Under the line of sight approach, a generation lead would be exempt from the requirements of FAC003-3 if personnel can see the generation lead corridor and the generation lead is less than a mile.
The rationale provided to support of this proposal is that “Stakeholders have generally supported the
rationale for exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit.” However, there is no data that supports that generation leads of less than a mile
are categorically not subject to vegetation contacts and outages. Further, in practice this approach
will unduly discriminate against longer generator leads, many of which are associated with renewable
energy resource, such as wind and solar. NextEra Energy Inc. (NextEra) believes a more technically
sound approach is that all generator leads be subject to FAC-003-3, with the opportunity to be
exempted from FAC-003-3 regulation upon an affirmative demonstration that no vegetation threat
exists. To implement this approach, NextEra proposes that FAC-003-3 applicability 4.3.1 be revised to
read as follows: “Overhead transmission lines, including generation leads, beyond the fenced area of
the generating station switchyard to the point of interconnection with a Transmission Owner and are:
4.3.1.1. Operated at 200kV or higher; or 4.3.1.2. Operated below 200kV identified as an element of
an IROL under NERC Standard FAC-014 by the Planning Coordinator; or. 4.3.1.3. Operated below 200
kV identified as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.”
NextEra would also propose to add a new section 4.3.2 that reads as follows: “If a Generator Owner
or Transmission Owner can demonstrate that the entire Right-of-Way is paved or otherwise devoid of
vegetation, and reasonably expected to remain so, the Generation Owner or Transmission Owner is
exempt from FAC-003-3.” In addition, NextEra proposes that the drafting team consider a megawatt
(MW) threshold for a generating plant from both a stand-alone and aggregate bases. For example, it
is unlikely that vegetation contact tripping a 50 megawatt generator (or a generator of 100 MWs in
the aggregate) connected to a robust transmission system with a large amount of load and generation
will adversely impact reliability. Thus, NextEra proposes the addition of a provision that exempts a
generation lead for stand-alone generators of 50 MWs and below and generators in the aggregate of
100 MWs and below, unless there is an affirmative request for the generator to comply with FAC-0033 by a Transmission Operator or Reliability Coordinator. Such a provision could read as follows:
“Unless a Transmission Operator or Reliability Coordinator requests in writing that a stand-alone
generator of 50 Megawatts (MWs) or below (with a 200 kV or above generation lead) or a generator
in the aggregate of 100 MWs or below (with a 200 kV or above generation lead) comply with FAC003-3, these classes of generators and their associated generation leads are exempt from complying
with FAC-003-3. In the event a Transmission Operator or Reliability Coordinator requests in writing
that a stand-alone generator of 50 Megawatts (MWs) or below (with a 200 kV or above generation
lead) or a generator in the aggregate of 100 MWs or below (with a 200 kV or above generation lead)
comply with FAC-003-3, the associated registered entity shall have one-year from the date of the
written correspondence to come into compliance with FAC-003-3.”
Group
Southwest Power Pool Standards Development Team
Jonathan Hayes
No
Clear line of sight” means the distance that can be seen by the average person “standing at ground
level “without special instrumentation (e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Individual
Jean Nitz
ACES Power Marketing
Yes
Group
Bonneville Power Administration
Chris Higgins
Yes
BPA has no other comments or concerns at this time.
Group
Southern Company
Antonio Grayson
No
The requirement as worded implies or could be interpreted to mean one's line of site would have to
originate at the generating station switchyard fence. The "clear line of site" should also include that
from a roadway that travels in proximity to the line. Such a roadway's purpose would likely include
access to the line for inspections, maintenance, travel from the plant to the transmission subsation,
etc. Since the terrain between the generating station switchyard fence and the point of
interconnection could obsure the view from the fence, the clear line of site from such a roadway
should be allowed. The requirement should be revised to read, "…or (2) does not have clear line of
sight1 from the generating station switchyard fence or a roadway to the point of interconnection with
a Transmission Owner's Facility."
Group
NERC Compliance Policy
Mike Garton
Yes
Dominion offers the following comments on the Implementation Plan for FAC-003-3: 1. The last
paragraph on page 2 refers to FAC-003-3 Requirement 1.3. FAC-003-3 does not appear to contain a
Requirement 1.3; therefore, Dominion recommends that the reference in the Implementation Plan be
clarified. 2. The 3rd paragraph on page 3 refers to FAC-003-3 Requirement 1.2. FAC-003-3 does not
appear to contain a Requirement 1.2; therefore, Dominion recommends that the reference in the
Implementation Plan be clarified.
Individual
Patrick Brown
Essential Power, LLC
Yes
Group
MRO NSRF
WILL SMITH
Yes
The NSRF agrees with the clarifying changes related to adding the phrase “…..do not have a clear line
of sight from the generating station switchyard fence to the point of interconnection with a
Transmission Owner’s Facility…….”, however, have the following comment for SDT consideration: •
The Evidence Retention in FAC-003-3, Part C, Compliance, and Section1.2implies that an entity is
required to retain evidence for the time period since the last audit. Since Generator Owners’ audit
cycles are six (6) years, and the following paragraph statesthat to show compliance for R1, R2, R3,
R5, R6 and R7is three calendar years unless directed by the CEA to retain longer as part of an
investigation, this section should be clarified to require six years retention for applicable Generator
Owners.
Individual
Russell A. Noble
Cowlitz County PUD
No
Cowlitz must agree with Exelon’s position insomuch that the vantage point must be related to the
generating station switchyard maintenance or the operation and maintenance of the generation plant
itself, and afford a clear perspective of vegetation proximity. Cowlitz also agrees with the SDT’s line of
sight clarifying verbiage. However, restricting the vantage point to the generating station switchyard
fence does not encompass the spirit of the exclusion. A short one-mile transmission interconnection
line – from the generating station switchyard to the interconnection point – that is frequently viewed
during the operation and maintenance of the generation plant itself should be the crux of the
exemption. The exact location, i.e., the generating station switchyard fence, of the vantage point is
not the make or break of whether the interconnection line will be routinely inspected by default. As an
example, consider a hydro project where the generating station switchyard may be located near the
tailrace inside a canyon. From the fence line of this particular switchyard, only the interconnection line
traversing up the canyon wall is visible. However, topside of the dam where maintenance and
operational personnel must daily traverse under the interconnection line to access the powerhouse
and switchyard may afford a clear view of both the generating station switchyard below and the
interconnection station which includes the whole interconnecting line in-between. Further, if parts of
the interconnecting line is viewable in two or even three vantage points beneath the interconnection
line during the normal transit to and from the generating station switchyard, the sum of which
comprises the whole line, can this not also meet the spirit of the exclusion? Conversely, Cowlitz does
not hold that any vantage point should be acceptable. Any vantage point that must require special
effort to access no matter the ease is not acceptable. Also, a perpendicular view of a line (not under
or near) complicates perception of the proximity of vegetation to a line. Views parallel down the rightof-way maximizes perception of vegetation proximity. Further, a long line that is fully viewable during
transit to and from the generation plant increases the chance of hidden vegetation encroachment.
Cowlitz strongly opposes any trivializing of reliability compliance collateral damage. Forcing
compliance activities with no reliability return must be avoided wherever possible. As a stakeholder
with limited time to invest reviewing all the comments submitted, Cowlitz offers an apology to Exelon
for missing their initial comment. Cowlitz commends Exelon’s persistence in this matter. ***
Suggested language: ...or (2) do not have a clear line of sight (leave the footnote in place) up and/or
down from a single vantage point within the transmission right-of-way where both the origin at the
generating station switchyard and the termination interconnection point with the Transmission
Owner’s Facility can be seen, and where operations or maintenance personnel frequent on foot during
normal generation plant or generating station switchyard access is made...
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
Yes
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07 (FAC-003-3 and FAC-003-x)
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments on the second formal posting of FAC-003-3 and FAC-003-X, as part of Project
2010-07—Generator Requirements at the Transmission Interface. These standards were posted for a
30-day public comment period from March 9, 2012 through April 9, 2012. Stakeholders were asked to
provide feedback on the standards and associated documents through a special electronic comment
form. There were 22 sets of comments, including comments from approximately 83 different people
from approximately 76 companies representing 9 of the 10 Industry Segments as shown in the table on
the following pages.
The SDT considered all comments submitted and has proposed the following minor changes to FAC003-X and FAC-003-3:
•
•
FAC-003-X:
The Applicability section was reformatted to make it clear that the standard applies on a
Facility by Facility basis (as in FAC-003-3), not simply to all generator interconnection
Facilities owned by a Generator Owner with at least one qualifying generator
interconnection Facility.
In the Purpose section, Right-of-Way was capitalized because it is an approved NERC
glossary term and “North American Electric Reliability Council” was changed to “North
American Electric Reliability Corporation.”
Regional Entity was added back to the Applicability section of the standard. Requirement
R4 is assigned to the Regional Entity, and the Project 2010-07 does not have the
authority, based on the scope outlined in its SAR, to modify that requirement. Thus,
Regional Entity must remain in the Applicability section. In all cases, Regional Entity has
been spelled out rather than referred to as “RE.”
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
FAC-003-3:
A typo was found in the Severe VSL for R2; the previous reference to “Transmission
Owner” was changed to “responsible entity,” as in all other FAC-003-3 VSLs.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
Other minority comments are addressed alongside their specific comments below.
Note that if both FAC-003-X and FAC-003-3 are approved in this recirculation ballot, only FAC-003-3 will
be presented to NERC’s Board of Trustees. FAC-003-X has been modified so that the generator
interconnection Facility gap can be quickly addressed in the event that neither FAC-003-2 nor FAC-003-3
is approved by FERC.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_Rev%201_20110825.pdf.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
2
Index to Questions, Comments, and Responses
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder
comments submitted in the first successive ballot between October 5 and November 18, 2011,
along with advice from NERC staff. The SDT continues to believe that a reference to line of sight is
clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the line of sight
reference but made a few additional changes for formatting clarity and language consistency. The
team also added a footnote to further explain what it means by “line of sight.” Do you agree with
these changes? If not, please provide specific alternative language. …. ........................................... 8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Michael R. Lombardi Northeast Utilities
NPCC 1
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Don Jones
Group
2
3
4
5
6
7
Texas Reliability Entity
Texas Reliability Entity
ERCOT 10
2. David Penney
Texas Reliability Entity
ERCOT 10
3.
Group
Southwest Power Pool Standards
Development Team
Jonathan Hayes
Additional Member Additional Organization
Region
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
X
X
X
X
X
Segment Selection
1.
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Curtis Crews
8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Charles
Sheppard
1
2. Rebecca
Berdahl
3
5.
Group
Mike Garton
NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
5, 6
2. Michael Crowley
Electric Transmission
SERC
1, 3
3. Jeff Bailey
Nuclear
MRO
5
4. Sean Iseminger
F&H
SERC
5
5. Chip Humphrey
F&H
NPCC 5
6.
Group
WILL SMITH
MRO NSRF
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL(NSP)
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTLESON
OTP
MRO
1, 3, 4, 5
14. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
15. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
16. THERESA ALLARD
MPC
MRO
1, 3, 5, 6
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7.
Individual
Antonio Grayson
Southern Company
X
8.
9.
Individual
Individual
Brenda Frazer
John Bee
Edison Mission Marketing & Trading
Exelon
X
X
10.
Individual
Ray Phillips
Alabama Municipal Electric Authority
11.
Individual
Joe Petaski
Manitoba Hydro
12.
Individual
Dan Roethemeyer
Dynegy
13.
Individual
Thad Ness
American Electric Power
X
X
X
X
14.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
15.
Individual
Dale Fredrickson
Wisconsin Electric
16.
Individual
Daniel Duff
Liberty Electric Power LLC
17.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
18.
Individual
Brian Murphy
NextEra Energy, Inc.
X
19.
Individual
Jean Nitz
ACES Power Marketing
20.
Individual
Patrick Brown
Essential Power, LLC
21.
Individual
Russell A. Noble
Cowlitz County PUD
22.
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
X
X
X
X
X
X
X
X
X
7
X
X
X
X
X
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments submitted in the first
successive ballot between October 5 and November 18, 2011, along with advice from NERC staff. The SDT continues to
believe that a reference to line of sight is clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the
line of sight reference but made a few additional changes for formatting clarity and language consistency. The team also
added a footnote to further explain what it means by “line of sight.” Do you agree with these changes? If not, please provide
specific alternative language.
Summary Consideration:
Some commenters still do not support the qualifying language for Generator Owners (GOs) or believe that the qualifying
language should be worded differently. The SDT continues to believe that the qualifying criteria for GOs are appropriate;
it has explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant
stakeholder comments, including many possible language options, and is satisfied that it has determined the appropriate
language to address the reliability gap.
Some commenters suggested changes to items – including the content of the VSLs and the tables attached to the
standard that were outside the scope of the SDT’s work.
Some commenters raised questions about the language differences between FAC-003-X and FAC-003-3 and expressed
concern that the language in FAC-003-X could lead to a “null” result whereby the qualifying language is not applied
according to the SDT’s intent. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the language in
4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written, now that it has been reformatted to better match the formatting in FAC-003-3.
Some commenters questioned whether “clear line of sight” means from a fixed point or from any point along the line.
The SDT clarified that it intends for the phrase “from the generating station switchyard fence to the point of
interconnection” to mean that there is a clear line of sight from any point along that length of line.
One commenter questioned whether the standard applies to all generator interconnection Facilities that a GO owns if it
applies to one of them. The SDT clarified that it intended for the standard to apply on a line by line basis in both FAC-003X and FAC-003-3. To clarify this, it has reformatted the Applicability section of FAC-003-X to better match the formatting
in FAC-003-3.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
8
One commenter asked whether the standard applies to the entirety of an applicable generator interconnection Facility,
or just the portion of the line greater than one mile. The SDT clarified that if a GO owns an applicable line, the GO is
responsible for the entirety of that line. The SDT believes that this is clear in the standards as written.
One commenter expressed concern that the implementation timeframe is too long. The SDT reminded the commenter
that the time frame was based on previous stakeholder comments and the fact that the implementation of Version 0
standards – the transition into which marked the time that TOs needed to begin applying FAC-003 on a mandatory basis –
occurred over more than two years. It is therefore reasonable to assume that GOs, having never had to comply with a
vegetation management standard, be afforded adequate time to do so.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previous
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
The SDT considered all comments received and decided to address typos, improve the formatting of the Applicability
section of FAC-003-X, and update the boilerplate language in the Effective Dates sections of the standards and their
implementations plans. The SDT has proposed no substantive changes to the standards.
Organization
Yes or No
Question 1 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact,
one could argue that a very short line, 300 feet in length, that experienced a
fault from a tree at "the end of the circuit", i.e near the switchyard fence,
would have much more of an impact on the BES because the fault would be
limited by much less impedance.
(b) For the GO that owns several lead lines but only one of the lines is
greater than one mile in length, does this standard apply to all the lead lines
he owns? A response can be affirmative with the current language of the
section 4.2.1. If this is not the intent, it should be clarified.
(c) It is also unclear in this version if a GO that owned one line that was 1.2
miles in length would have to comply for the entire length of said line, or
just 0.2 miles of said line. If the GO is responsible for 1.2 miles, then that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
9
Organization
Yes or No
Question 1 Comment
argues that the first mile is important and consequently there is no basis for
ignoring the first mile on other lines. If the GO is only responsible for 0.2
miles, what is the technical basis to ignore a mile? And would it be the first
mile from the switchyard that is ignored, or is the middle mile, or the last
mile where it connects to the TO? Or could the GO decide? Or could the GO
pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(d) The 2 year compliance time line is far too long. There is significant
industry evidence that was developed in the drafting of Version 2 that
supports a one year compliance time-line for new lines. This is evidenced in
Version 2. Thus there is no basis for the 2 years
Response: Thank you for your comment. The SDT continues to believe that the qualifying criteria for GOs are appropriate; it has
explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap.
The SDT intended for the standard to apply on a line by line basis in both FAC-003-X and FAC-003-3. To clarify this, it has
reformatted the Applicability section of FAC-003-X to better match the formatting in FAC-003-3.
If a GO owns an applicable line, the GO is responsible for the entirety of that line. The SDT believes that this is clear in the
standards as written.
With respect to the Implementation Plan, the SDT reminds Ameren that the time frame was based on previous stakeholder
comments and the fact that the implementation of Version 0 standards – the transition into which marked the time that TOs
needed to begin applying FAC-003 on a mandatory basis – occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do so.
BC Hydro and Power Authority
Negative
“BC Hydro agrees with the revisions to FAC-003-3 and would vote
Affirmative except for the following two items.
One: The FAC-003-2 adopted by the NERC Board of Trustees had a
significant change to what was voted on in Draft 6 in the Table of
Compliance Elements (R1 and R2). In the table on Page 13 of the version
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
10
Organization
Yes or No
Question 1 Comment
adopted by the NERC Board of Trustees on November 3, 2011, the VSLs
were changed and the staff proposed violation severity levels were adopted
and the review team recommendations were rejected. Therefore, there is
no Low or Moderate VSLs for these two violations only High and Severe.
This was rejected earlier by a number of utilities including BC Hydro and was
not in the version 6 draft that was voted for on the last ballot. This change
as adopted is a concern as it expects a level of program perfection that
seems unrealistic. It is also at odds with the Rationale for R1 and R2 outlined
on Page 32 of the standard “Guideline and Technical Basis” section which
gives an explanation for the increasing levels of violation severity. Program
failures that were deemed to be “unusual conditions in an otherwise sound
program” or “not adequately addressed by the program” formerly rated as
Lower or Moderate VSL are now rated as High. It also extends the severity
of the violation beyond what is currently in FAC-003-1 although the levels of
non-compliance are not strictly comparable between versions. This change
is carried on in the Draft FAC-003-3.
Two: Table 2 (pg. 30 and 31 of FAC-003-3 Draft 3) for Minimum Vegetation
Clearance Distances for AC Voltages now includes clearance calculations for
287 kV which is good and was something BC Hydro asked for. However, the
calculations don’t seem to be correct as the limits are higher than for
345kV. BC Hydro recommends either providing an explanation as to why
these limits seem to be out of sequence to increasing voltage or recalculate
them.”
Response: Thank you for your comment. The SDT's SAR is very limited in scope (determining which additional standards should
apply to a GO/GOP). The SDT made no changes to the VSLs and simply included the FAC-003-2 VSLs that were approved by
NERC’s BOT, as those are the VSLs that will be filed with FERC. Similarly, the SDT made no changes to Table 2, as that would also
have been outside its scope; the SDT exclusively made changes that would add GOs or GOPs to standard requirements or
applicability sections, and changes that would bring the standard up to date according to current NERC templates. No change
made.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
11
Organization
Yes or No
Question 1 Comment
ComEd
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
PECO Energy
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
Gulf Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Mississippi Power
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Alabama Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Utility Services, Inc.
Negative
The applicability language under Version X is not the same as the language
in Version 3. We do not believe that applicability language in Version X can
ever result in a “True” logical outcome whereas the language in Version 3
can. We understand the intent; however, applying the specific language
using the logical "AND" in the applicability portion of the standard will
always come out with a null result. We suggest the SDT adopt the
applicability language in Version 3 in Version X.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
language in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that it has been reformatted to better match the formatting in FAC-003-3. No
change made.
Xcel Energy, Inc.
Negative
This project is counter-productive to the efforts of the Protection System
Maintenance and Testing Standard Drafting Team that concurrently has
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
12
Organization
Yes or No
Question 1 Comment
PRC-005-2 posted for comment and successive ballot.
Response: Thank you for your comment. The SDT believes this comment was submitted in response to PRC-005 and will address
it with comments received under that standard.
SERC Reliability Corporation
Negative
We have concern that if this passes there will be BES Elements that will not
be covered by the vegetation management standard that are currently
included in the standards and that this determiniation is based solely on
ownership and not risk to reliability. SERC supports BES reliability and as
veggetation management was identified as a significant contributor to the
2003 Blackout we do not support a revision that would create a gap in the
results-based, defense-in-depth approach that has been determined to be
necesary for the reliable operation of the interconnected transmission
network.
Response: Thank you for your comment. GOs are not currently covered under any vegetation management requirements, so the
SDT does not understand the comment about removing coverage for BES Elements “that are currently included in standards.”
The applicability to TOs, the entity currently subject to vegetation management requirements, is not changing. The SDT
recognizes that in many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2) the
overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for exempting these Facilities
because incorporating them into FAC-003 would offer no reliability benefit. No stakeholder has commented that there are
similarly situated transmission facilities.
Southern Company
No
The requirement as worded implies or could be interpreted to mean one's
line of site would have to originate at the generating station switchyard
fence. The "clear line of site" should also include that from a roadway that
travels in proximity to the line. Such a roadway's purpose would likely
include access to the line for inspections, maintenance, travel from the
plant to the transmission subsation, etc. Since the terrain between the
generating station switchyard fence and the point of interconnection could
obsure the view from the fence, the clear line of site from such a roadway
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
13
Organization
Yes or No
Question 1 Comment
should be allowed. The requirement should be revised to read, "...or (2)
does not have clear line of sight1 from the generating station switchyard
fence or a roadway to the point of interconnection with a Transmission
Owner's Facility."
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap. No change made.
Southwest Power Pool Standards
Development Team
No
Clear line of sight” means the distance that can be seen by the average
person “standing at ground level “without special instrumentation (e.g.,
binoculars, telescope, spyglasses, etc.) on a clear day.
Response: Thank you for your comment. The SDT has considered all relevant stakeholder comments and is satisfied that we
have determined the appropriate language to address the reliability gap.
Cowlitz County PUD
No
Cowlitz must agree with Exelon’s position insomuch that the vantage point
must be related to the generating station switchyard maintenance or the
operation and maintenance of the generation plant itself, and afford a clear
perspective of vegetation proximity. Cowlitz also agrees with the SDT’s line
of sight clarifying verbiage. However, restricting the vantage point to the
generating station switchyard fence does not encompass the spirit of the
exclusion. A short one-mile transmission interconnection line - from the
generating station switchyard to the interconnection point - that is
frequently viewed during the operation and maintenance of the generation
plant itself should be the crux of the exemption.
The exact location, i.e., the generating station switchyard fence, of the
vantage point is not the make or break of whether the interconnection line
will be routinely inspected by default. As an example, consider a hydro
project where the generating station switchyard may be located near the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
14
Organization
Yes or No
Question 1 Comment
tailrace inside a canyon. From the fence line of this particular switchyard,
only the interconnection line traversing up the canyon wall is visible.
However, topside of the dam where maintenance and operational
personnel must daily traverse under the interconnection line to access the
powerhouse and switchyard may afford a clear view of both the generating
station switchyard below and the interconnection station which includes
the whole interconnecting line in-between.
Further, if parts of the interconnecting line is viewable in two or even three
vantage points beneath the interconnection line during the normal transit
to and from the generating station switchyard, the sum of which comprises
the whole line, can this not also meet the spirit of the exclusion?
Conversely, Cowlitz does not hold that any vantage point should be
acceptable. Any vantage point that must require special effort to access no
matter the ease is not acceptable. Also, a perpendicular view of a line (not
under or near) complicates perception of the proximity of vegetation to a
line. Views parallel down the right-of-way maximizes perception of
vegetation proximity.
Further, a long line that is fully viewable during transit to and from the
generation plant increases the chance of hidden vegetation encroachment.
Cowlitz strongly opposes any trivializing of reliability compliance collateral
damage. Forcing compliance activities with no reliability return must be
avoided wherever possible. As a stakeholder with limited time to invest
reviewing all the comments submitted, Cowlitz offers an apology to Exelon
for missing their initial comment. Cowlitz commends Exelon’s persistence in
this matter.
***Suggested language: ...or (2) do not have a clear line of sight (leave the
footnote in place) up and/or down from a single vantage point within the
transmission right-of-way where both the origin at the generating station
switchyard and the termination interconnection point with the Transmission
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
15
Organization
Yes or No
Question 1 Comment
Owner’s Facility can be seen, and where operations or maintenance
personnel frequent on foot during normal generation plant or generating
station switchyard access is made...
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. We do not believe that adding the language you
suggest necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has considered all
relevant stakeholder comments and is satisfied that we have determined the appropriate language to address the reliability
gap. No change made.
Exelon
No
Exelon disagrees with the current proposed draft of FAC-003-3/X because
the reference to a “clear line of sight from the generating station switchyard
fence to the point of interconnection” does not clarify the Standard and is
unsupported by any technical basis. Furthermore, the definition of “clear
line of sight” added by the SDT does not address or remedy the substantive
concerns raised in Exelon’s appeal.
Exelon reiterates that the SDT should base the applicability of the Standard
on the length of the transmission line, a measurable component of the bulk
electric system, and remove all references to a “clear line of sight.” This
approach is consistent with previous draft versions of FAC-003 proposed by
the SDT and the Ad Hoc Group and the recent recommendation of the NERC
Vice President of Standards and Training in response to Exelon’s appeal.
Alternatively, if the “clear line of sight” verbiage remains, the Standards
should be clarified to remove the requirement that the line of sight be
established from “the generating station switchyard fence to the point of
interconnection” and to add a requirement or clarify that “clear line of
sight” for lines of one mile or less can include observation of the length of
the transmission lines from various vantage points within the owner
controlled property. The SDT states in the “Background” section of the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
16
Organization
Yes or No
Question 1 Comment
Unofficial Comment Form that “a reference to the line of sight is clarifying
and makes explicit the SDT’s implicit intent from day one.”
Yet, the SDT offers no support for its “implicit intent from day one,” and a
review of the history for these Standards certainly does not support an
“implicit intent from day one” to require a clear line of sight from a fixed
location, let alone the generating station switchyard fence, to the point of
interconnection. The Technical Justification document posted in September
2011 (p. 3) refers to the Ad Hoc Group’s original thought to exclude from
the Standards any transmission lines that were “less than two spans [long]
(generally one half mile from the generator property line).” In agreeing
“with that intended exclusion in principle,” the SDT explained (p. 3) that,
“[a]fter reviewing formal comments, the SDT agreed to revise the exclusion
so that it applies to a Facility [transmission line] if its length is ‘one mile or
1.609 kilometers beyond the fenced area of the generating station
switchyard’ to approximate line of sign [sic] from a fixed point,” (the fixed
point being the fenced area of the generating station switchyard). From the
start, the Ad Hoc Group and SDT focused on the length of the transmission
line (either a half mile as proposed by the Ad Hoc Group or a mile as
proposed by the SDT) as the proxy for line of sight, the presumption being
that up to a certain distance, the overhead line is in the line of sight at
various locations throughout the Generator Owner’s property and
reasonably subject to being managed through normal day-to-day plant
activities.
The SDT has not, until the most recent iteration of the Standards, focused
on requiring a “clear line of sight from the generating station switchyard
fence to the point of interconnection.” As support for adding the “clear line
of sight” requirement to the FAC-003-3/X Standards in December 2011, the
SDT noted as follows: “We believe that the one mile length is a reasonable
approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
17
Organization
Yes or No
Question 1 Comment
any discretion on the part of a Generator Owner or an auditor.” With the
addition of an explicit line of sight reference here, the SDT believes it has
clarified its original intent. (Side bar comments to FAC-003-3, Section 4.3.1
(December 1, 2011); FAC-003-X, Section 4.3.1 (December 1, 2011)).
This explanation does nothing more than (1) reiterate the point the SDT has
maintained throughout the entire drafting process, namely that “the one
mile length” of a transmission line “is a reasonable approximation of line of
sight,” and (2) explain that the SDT included a “fixed starting point” (the
fenced area of the generation station switchyard) from which to measure
the length of the transmission line to address stakeholder concerns about
excessive Generator Owner discretion with respect to the location from
which to take a measurement and inconsistent application of the Standards.
Again, the SDT’s “intent” (implicit or otherwise) “from day one” has nothing
to do with establishing a “clear line of sight from the generating switchyard
fence to the point of interconnection.” In addition, requiring a “clear line of
sight from the generating station switchyard fence to the point of
interconnection” is technically unsupported. The SDT just added the
requirement for a “clear line of sight to the point of interconnection”
language without considering the implications of why such a change was
required or reasonable. While a specific fixed starting point (the generating
station switchyard fence) and end point (the point of interconnection) may
make sense for establishing a starting and ending point from which to
measure the length of the transmission line (the one-mile limitation), it does
not make sense when considering a clear line of sight, especially in light of
stakeholder comments and the SDT’s repeated acknowledgment that in
many cases, generation Facilities are either (1) staffed and the overhead
portion is within the line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
18
Organization
Yes or No
Question 1 Comment
these qualifiers represent a reasonable and appropriate risk prevention
approach.(Consideration of Comments, Generator Requirements at the
Transmission Interface, Project 2010-07 (for November 9, 2011 successive
ballot), p. 1; Technical Justification Resource Document (posted March
2012), p. 3.)
By inserting the “clear line of sight” requirement now without modifying the
fixed starting point, the SDT completely ignores its unequivocal
acknowledgment that generation Facilities are unique in the sense that
personnel can see the line from various locations within the owner
controlled area and many generation Facilities are over paved surfaces. The
absence of a technical justification for imposing a “clear line of sight” is
illustrated by the following example.
A Generator Owner transmission line leaving the generating station could
take a “dog leg” turn (the line turns at one of the towers). Standing at the
tower in this example, an individual would have a clear line of sight of the
entire line to either end of the short-distance line (to the end leaving the
station and to the end terminating at the point of interconnection). Since
the generating Facility is within the Generator Owner’s property line or
controlled area and consistently staffed by personnel who patrol the owner
controlled area, the line can be observed and maintained by staff in the
same manner as any other short distance line with a “clear” line of sight
from the “generating station switchyard fence to the point of
interconnection.” Moreover, to the extent a portion or the entire length of
the line travels over paved surfaces or structures, any barriers or obstacles
to a clear line of sight will not be caused by vegetation, as discussed in FAC003-3/X but, rather, by equipment, components, or structures. Clearance
between generator lines and structures is already covered in other NERC
Standards. For those lines that do travel over areas of vegetation, the
regular personnel monitoring and surveillance of the areas over which the
lines travel provides reasonable assurance of protection from vegetation
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
19
Organization
Yes or No
Question 1 Comment
related events.
Rather than clarifying the Standards, the SDT has introduced more
ambiguity into the Standards. The addition of the “generating station
switchyard fence” as the point of reference for a clear line of sight adds
more confusion than it solves by introducing a variable that will be left to
the discretion of generator owner and an auditor. What is the definition of
a “generating station switchyard fence?” As Exelon noted in its Appeal and
at least one other Registered Entity noted in its Comments for the first
successive ballot (Consideration of Comments posted March 2012, p. 38),
some generation facilities do not have generating switchyards or generating
switchyard fences. A requirement that there be a clear line of sight from the
“generating switchyard fence” is meaningless in cases where no such
switchyard or fence exists. Is it the fence surrounding the generating unit or
is it meant to refer to the fence surrounding the Transmission Owner’s
associated switchyard and relay house? What if there are multiple physical
fence lines between the generating unit and the point of interconnection?
In addition, by introducing a point of reference that is not a physical
component or measurable reference of the bulk electric system, what
precludes the Generator Owner from arbitrarily moving the fence line to
avoid applicability? Also lacking in clarity is the addition of a footnote
defining “clear line of sight” to mean “the distance that can be seen by the
average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.” Generation Owners will be left to
determine what constitutes an “average person,” a “clear day,” and “special
instrumentation.”
For all these reasons, Exelon requests that the SDT base the applicability of
the Standard on the length of the transmission line, a measurable
component of the bulk electric system, and remove all references to a
“clear line of sight.” Alternatively, if the “clear line of sight” verbiage
remains, the Standards should be clarified to remove the requirement that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
20
Organization
Yes or No
Question 1 Comment
the line of sight be established from “the generating station switchyard
fence to the point of interconnection” and to add a requirement or clarify
that “clear line of sight” for lines of one mile or less can include observation
of the length of the transmission lines from various vantage points within
the owner controlled property.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt.
The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that
there is a clear line of sight from any point along that length of line. We do not believe that adding a reference to a fixed
vantage point necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has
considered all relevant stakeholder comments and is satisfied that we have determined the appropriate language to address
the reliability gap. No change made.
Texas Reliability Entity
No
In FAC-003-X:
1. We appreciate that you took Regional Entity out of the Applicability
section, but there is still a Requirement (R4) that applies to the Regional
Entity. Is that Requirement intended to be enforceable against the Regional
Entities? We suggest removing Requirement R4.
2. In Part D.1.1, only the Regional Entity should be listed as Compliance
Monitor, since the Regional Entity has been removed as an Applicable
entity.
3. In the Purpose section, update the reference to NERC (use “Corporation”
instead of “Council”), and capitalize “Rights-of-Way” since it is a defined
term.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
21
Organization
Yes or No
Question 1 Comment
4. We suggest that you spell out “Regional Entity” in Applicability part 4.2.1.
5. In the implementation plan, the reference to “R3” should be corrected to
“R1” in the following sentence: “In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of
the first calendar quarter one year following Board of Trustees adoption.”
In FAC-003-3:
6. There is no Compliance Monitor listed on page 17. At least the Regional
Entity should be listed here.
7. In the Severe VSL for R2, replace “Transmission Owner” with
“responsible entity.”
8. In the Severe VSL for R1 and R2, remove “active transmission line” before
“ROW.” That phrase is confusing in the VSLs because it does not appear in
the requirements, and it is not clear whether it is intended to change the
requirements.
9. In Table 2 (Alternating Current - meters AND Direct Current) the footnote
references are wrong. We think they should be 9 and 10, rather than 7 and
8.
10. In Table 2 (Direct Current), the column headings are wrong. Only the
first column heading should refer to voltage. The rest should refer to
MVCD.
Response: Thank you for your comment.
1. The SDT has reverted back to the original Applicability (which included the Regional Entity) because deleting a requirement
is outside the scope of this drafting team.
2. Because the Regional Entity was returned to the Applicability section, the second bullet in section D1.1 must remain.
3. Changes made.
4. Regional Entity has been spelled out in all cases.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
22
Organization
Yes or No
Question 1 Comment
5.
6.
7.
8.
Change made.
The Compliance Enforcement Authority section has been updated as suggested.
Change made.
Modifying the VSLs beyond the change from “Transmission Owner” to “responsible entity” is not within the scope of the
SDT, and these VSLs have already been approved by NERC’s BOT.
9. These are 9 and 10 in both the clean version and the redline version.
10. The Project 2010-07 SDT did not modify this table.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project
2010-07. If a Generator Owner is required to register as a TO, all the
Requirements applicable to a TO should apply. There is no need to change
specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions.For additional information, please see Manitoba
Hydro's comments submitted in the comment period ending November 18,
2011. Manitoba Hydro does not believe that the SDT fully addressed our
concerns in their responses to our comments in that commenting period.
Response: Thank you for your comment. Under the SDT’s changes, GOs are not going to be required to register as TOs, so this
comment does not apply.
To reiterate our comments in previous comment reports, the intent of the SDT’s SAR is to address all reliability gaps associated
with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should
first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”
posted alongside the December ballot) – that is, a Facility used to connect one or more generators to a Facility owned or
operated by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection
Facility owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission
Interface Background Resource Document.
Liberty Electric Power LLC
No
The "line of sight" should be removed. It opens up the entity to a finding of
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
23
Organization
Yes or No
Question 1 Comment
non-compliance if a temporary blockage of line of sight should occur.
Response: Thank you for your comment. We maintain that the addition of the reference to “clear line of sight” is clarifying and
helps support the rationale behind the one mile exemption. A line less than one mile that passes through a dense grove should
not be exempt from this standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over
a paved surface should be exempt. Nothing in the proposed standard prohibits an entity from self-imposing the requirements
contained within in order to mitigate any perceived risk of potential non-compliance. No change made.
Northeast Power Coordinating
Council
No
The Applicability language used in FAC-003-X is different from that used in
FAC-003-3. The language used in FAC-003-X uses “and” in several places
which leads to confusion and a probable “null” result, whereas the language
in FAC-003-3 is more straightforward and makes use of “or”. The FAC-003-3
applicability language should be used in FAC-003-X.The explanation of what
is meant by line of sight should be incorporated in the Applicability Section
wording as standards, at NERC’s direction, are supposed to be getting away
from the use of footnotes.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
formatting in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that the formatting has been updated to better reflect the formatting in FAC-0033. No change made.
NextEra Energy, Inc.
No
Under the line of sight approach, a generation lead would be exempt from
the requirements of FAC-003-3 if personnel can see the generation lead
corridor and the generation lead is less than a mile. The rationale provided
to support of this proposal is that “Stakeholders have generally supported
the rationale for exempting these Facilities because incorporating them into
FAC-003 would offer no reliability benefit.”
However, there is no data that supports that generation leads of less than a
mile are categorically not subject to vegetation contacts and outages.
Further, in practice this approach will unduly discriminate against longer
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
24
Organization
Yes or No
Question 1 Comment
generator leads, many of which are associated with renewable energy
resource, such as wind and solar.
NextEra Energy Inc. (NextEra) believes a more technically sound approach is
that all generator leads be subject to FAC-003-3, with the opportunity to be
exempted from FAC-003-3 regulation upon an affirmative demonstration
that no vegetation threat exists.
To implement this approach, NextEra proposes that FAC-003-3 applicability
4.3.1 be revised to read as follows: “Overhead transmission lines, including
generation leads, beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner and
are:4.3.1.1. Operated at 200kV or higher; or 4.3.1.2. Operated below 200kV
identified as an element of an IROL under NERC Standard FAC-014 by the
Planning Coordinator; or. 4.3.1.3. Operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.”
NextEra would also propose to add a new section 4.3.2 that reads as
follows:”If a Generator Owner or Transmission Owner can demonstrate that
the entire Right-of-Way is paved or otherwise devoid of vegetation, and
reasonably expected to remain so, the Generation Owner or Transmission
Owner is exempt from FAC-003-3.”
In addition, NextEra proposes that the drafting team consider a megawatt
(MW) threshold for a generating plant from both a stand-alone and
aggregate bases. For example, it is unlikely that vegetation contact tripping
a 50 megawatt generator (or a generator of 100 MWs in the aggregate)
connected to a robust transmission system with a large amount of load and
generation will adversely impact reliability.
Thus, NextEra proposes the addition of a provision that exempts a
generation lead for stand-alone generators of 50 MWs and below and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
25
Organization
Yes or No
Question 1 Comment
generators in the aggregate of 100 MWs and below, unless there is an
affirmative request for the generator to comply with FAC-003-3 by a
Transmission Operator or Reliability Coordinator. Such a provision could
read as follows:”Unless a Transmission Operator or Reliability Coordinator
requests in writing that a stand-alone generator of 50 Megawatts (MWs) or
below (with a 200 kV or above generation lead) or a generator in the
aggregate of 100 MWs or below (with a 200 kV or above generation lead)
comply with FAC-003-3, these classes of generators and their associated
generation leads are exempt from complying with FAC-003-3. In the event a
Transmission Operator or Reliability Coordinator requests in writing that a
stand-alone generator of 50 Megawatts (MWs) or below (with a 200 kV or
above generation lead) or a generator in the aggregate of 100 MWs or
below (with a 200 kV or above generation lead) comply with FAC-003-3, the
associated registered entity shall have one-year from the date of the written
correspondence to come into compliance with FAC-003-3.”
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. And because there are many GOs whose lines would fall into these categories, the SDT believes the exemption is
necessary and prevents GOs with little to no reliability risk from incurring undue cost and compliance risk in the development
and maintenance of a vegetation management plan. In sum, the SDT has considered all relevant stakeholder comments and is
satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Dynegy
No
Using the switchyard fence is to restrictive. There could be to many
different layouts to keep it fair for all GO's. For example, there could be an
obstruction if limited to standing at the existing switchyard fence but if one
were to move a short distance away (i.e. corner of GO's building) then it
could be possible to see both ends of the tie line. This would also meet the
intent of the added language since it is now within line of sight. I
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
26
Organization
Yes or No
Question 1 Comment
recommend deleting "switchyard fence". Also, in order to account for a GO
not being able to dictate what happens inside a TO's switchyard, I
recommend adding "entry or" between "of" and "interconnection".
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and believes that using the fixed starting point of the
switchyard fence is best for eliminating confusion and any discretion on the part of a Generator Owner or an auditor. The SDT
intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that there is a
clear line of sight from any point along that length of line. In sum, the SDT has considered all relevant stakeholder comments
and is satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Wisconsin Electric; Wisconsin
Electric Power Co.; Wisconsin
Electric Power Marketing; Wisconsin
Energy Corp.
No
We strongly oppose the addition of the “clear” line of sight criteria to the
Applicability. The report of the GOTO Task Force, as well as prior draft
revisions to FAC-003, included a test based solely on circuit length, which is
sufficient in our view to assure that the BES is not at risk due to vegetation
issues on generator tie lines. The expansion to include short tie lines,
including those entirely on the Generator Owner’s property which may not
meet the line of sight qualifier, has no benefit to reliability. Rather, the
expanded applicability and the requirement for a formal vegetation
management program in these cases will consume resources for compliance
that are better used for actual reliability improvements.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. The SDT has considered all relevant stakeholder comments and is satisfied that we have determined the
appropriate language to address the reliability gap. No change made.
ExxonMobil Research and
Engineering
No
While it is clear that the SDT is attempting to include those facilities owned
by Generator Owners that travel long distances down right-of-ways, the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
27
Organization
Yes or No
Question 1 Comment
applicability section of FAC-003-X and FAC-003-3, as written, require
industrial complexes with cogeneration facilities to develop Transmission
Vegetation Management Programs for generator lead lines that are not
exposed to vegetation.
Industrial cogeneration location is typically chosen based on the availability
of fuel, need for steam, or availability of real estate. This can result with the
generation facilities (including the GSU transformer substation) being
located deep within the plant with long cable routes and multiple substation
connections between the GSU transformer substation and utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. Additionally, the routes of these generator lead lines
fundamentally differ in nature from a typical IPP’s generator lead line route.
Since they are located within the fence line of an industrial complex, the
routes rarely contain vegetation; are frequently travelled by plant
personnel; rarely run in straight lines (i.e. no single line of sight); and
frequently terminate at a facility located at the fence line of the industrial
complex where a transmission company takes ownership of the power lines
that leave the industrial complex. Furthermore, the use of the term
“generating station switchyard” may result in inconsistent enforcement of
the Transmission Vegetation Management Program Reliability Standard as
the use of the term implies there is only one substation located within a
Generator Owner’s complex. Typically, there are multiple substations that
connect an industrial complex’s generator lead-line to the utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. The two obvious interpretations for the “generating
station switchyard” are the substation that is directly connected to the
generator’s GSU, and the utility interconnection facility. The concerns
raised by NERC and FERC staff related generator owned transmission like
assets originate with those conductors that leave the Generator Owner’s
complex’s fence line and travel long distances down vacant right-of-ways,
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
28
Organization
Yes or No
Question 1 Comment
and, therefore, the applicability of those Reliability Standards that apply to
transmission facilities should start with the fence line.
Since the Bulk Electric System is contiguous, reliability concerns related to
the facilities between the GSU transformer substation and utility
interconnection facility are covered by those Reliability Standards that apply
to Generator Owners and Generator Operators. In order to account for the
different nature of industrial complex’s generation facilities, the SDT should
consider re-phrasing the applicability section of FAC-003-X and FAC-003-3 to
start counting the length of a generator lead line at the fence line of the
Generator Owner’s complex and not the generating station switchyard.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and for language in general within this qualifier, and it
believes that using the fixed starting point of the switchyard fence is best for eliminating confusion and any discretion on the
part of a Generator Owner or an auditor. In sum, the SDT has considered all relevant stakeholder comments and is satisfied that
we have determined the appropriate language to address the reliability gap, while exempting the most common lines with little
to no reliability risk for a vegetation issue. No change made.
City of Bartow, Florida; City of
Clewiston; Florida Municipal Power
Agency; Beaches Energy Services
Affirmative
Although we are supporting the change, the added applicability language
for GOs is ambiguous as to whether the qualifier "operated at 200 kV and
above and any lower voltage lines designated by the Regional Entity as
critical to the reliability of the electric system in the region" applies to both
portions of the applicability (e.g., 1) > 1 mile and 2) no clear line of sight), or
just to the second no clear line of sight applicability. FMPA assumes that the
qualifier applies to both. We recommend re-arranging of the sentence to
make this clearer by moving the qualifier to the beginning of the sentence
instead of the end of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the qualifier language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with 4.1.1 of FAC-003-X. No change
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
29
Organization
Yes or No
Question 1 Comment
Affirmative
AWEA supports the modifications in this standard, along with the other
standards modification under Project 2010-07, as a reasonable approach to
addressing the perceived reliability concerns with generator tie lines. We
believe a consistent approach for all Generator Owners and Generator
Operators that does not require registration as a Transmission Owner or
Transmission Operator is the most efficient and effective way to address
these concerns.
made.
American Wind Energy Association
Response: The SDT thanks you for your comment and support.
BrightSource Energy, Inc.
Affirmative
BrightSource would like to thank the SDT for the effort in developing the
standard. Our comment is more on providing more clarification. Depending
on the agreements between the TO and the GO, the Point of
Interconnection is not necessarily the point of change of ownership of the
transmission facilities. For example, the GO may own the portion of the
Gen-tie from the generating plant to the last tower outside the TO’s
substation and the TO owns the line drop from the last tower to the
termination equipment inside the TO substation. So to avoid confusion later
we suggest that we modify P4.3.1 by adding “to the point of change of
ownership or” as follows: “4.3.1. Generator Owner that owns an overhead
transmission line(s) that (1) extends greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to
the point of change of ownership or to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight1 from
the generating station switchyard fence to the point of interconnection with
a Transmission Owner’s Facility and is operated at 200 kV and above and
any lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.” Thank you.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
30
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comment and support. The SDT considered many different language choices for its
qualifying language, and it believes that “point of interconnection” is a clear phrase that will be understood and appropriately
applied. No change made.
Indiana Municipal Power Agency
Affirmative
IMPA supports the change, but would add the comment that the added
applicability language for GOs is ambiguous as to whether the qualifier
"operated at 200 kV and above and any lower voltage lines designated by
the Regional Entity as critical to the reliability of the electric system in the
region" applies to both portions of the applicability which are 1) > 1 mile
and 2) no clear line of sight), or just to the second portion for no clear line of
sight applicability. IMPA assumes that the qualifier applies to both. We
recommend reorganizing the sentence to make this more clear by moving
the qualifier to the beginning of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the exemption language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with the formatting in 4.1.1 of FAC003-X. No change made.
Nebraska Public Power District
Affirmative
NPPD joins the comments submitted by the MRO NSRF (Midwest Reliability
Organization - NERC Standards Review Forum)
Midwest Reliability Organization
Affirmative
Please refer to comments made by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review
Forum.
Lakeland Electric
Affirmative
See FMPA comments
Great River Energy
Affirmative
See NSRF comments
Bonneville Power Administration
Yes
BPA has no other comments or concerns at this time.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
31
Organization
NERC Compliance Policy
Yes or No
Yes
Question 1 Comment
Dominion offers the following comments on the Implementation Plan for
FAC-003-3:
1. The last paragraph on page 2 refers to FAC-003-3 Requirement 1.3. FAC003-3 does not appear to contain a Requirement 1.3; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
2. The 3rd paragraph on page 3 refers to FAC-003-3 Requirement 1.2. FAC003-3 does not appear to contain a Requirement 1.2; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
Response: Thank you for these suggestions. These references have been removed.
MRO NSRF
Yes
The NSRF agrees with the clarifying changes related to adding the phrase
“.....do not have a clear line of sight from the generating station switchyard
fence to the point of interconnection with a Transmission Owner’s
Facility.......”, however, have the following comment for SDT consideration:
o The Evidence Retention in FAC-003-3, Part C, Compliance, and
Section1.2implies that an entity is required to retain evidence for the time
period since the last audit. Since Generator Owners’ audit cycles are six (6)
years, and the following paragraph statesthat to show compliance for R1,
R2, R3, R5, R6 and R7is three calendar years unless directed by the CEA to
retain longer as part of an investigation, this section should be clarified to
require six years retention for applicable Generator Owners.
Response: Thank you for your comment. The SDT believes the data retention section is appropriate as written. No change made.
Edison Mission Marketing & Trading
Yes
Alabama Municipal Electric
Authority
Yes
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
32
Organization
Yes or No
American Electric Power
Yes
Public Service Enterprise Group
Yes
ACES Power Marketing
Yes
Essential Power, LLC
Yes
Ingleside Cogeneration LP
Yes
Question 1 Comment
END OF REPORT
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
33
Herb Schrayshuen
Vice President, Standards and Training
February 14, 2012
Via E-Mail
Mr. Steven T. Naumann
Vice President, Wholesale Market Development
Federal Regulatory Affairs & Public Policy
Exelon Corporation
Chase Tower-50th Floor
10 S. Dearborn Street
Chicago, Il 60603
Re: Exelon Level 1 Appeal of FAC-003x in Project 2010-07
Dear Steve,
In my role as Director of Standards you informed me, on January 13, 2012, of the possibility of filing an
appeal. On January 20, 2012 you filed, on the behalf of Exelon Corporation, a Level 1 Appeal of the
processing of FAC-003 in Project 2010-07 under the NERC standards development process and the
Rules of Procedure Section 300. In its appeal Exelon is contending that there was an improperly
implemented, substantive change to the standard (R4.3.1) regarding “line of site” between the last
successive and recirculation ballot.
Level 1 Appeals are managed within the current NERC Standard Processes Manual (SPM) dated
September 3, 2010 as follows:
•
Any entity that has directly and materially affected interests and that has been or will be adversely
affected by any procedural action or inaction related to the development, approval, revision,
reaffirmation, or withdrawal of a reliability standard, definition, variance, associated implementation
plan, or interpretation shall have the right to appeal. This appeals process applies only to the NERC
reliability standards processes as defined in this manual, not to the technical content of the standards
action.
The burden of proof to show adverse effect shall be on the appellant. Appeals shall be made within 30
days of the date of the action purported to cause the adverse effect, except appeals for inaction, which
may be made at any time.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
The final decisions of any appeal shall be documented in writing and made public.
The appeals process provides two levels, with the goal of expeditiously resolving the issue to the
satisfaction of the participants.
•
Level 1 Appeal
Level 1 is the required first step in the appeals process. The appellant shall submit (to the Director of
Standards) a complaint in writing that describes the procedural action or inaction associated with the
standards process. The appellant shall describe in the complaint the actual or potential adverse impact
to the appellant. Assisted by staff and industry resources as needed, the Director of Standards shall
prepare a written response addressed to the appellant as soon as practical but not more than 45 days
after receipt of the complaint. If the appellant accepts the response as a satisfactory resolution of the
issue, both the complaint and response shall be made a part of the public record associated with the
standard.
The FAC-003-x standard had been scheduled for Board of Trustees approval at its February 9, 2012
meeting, however, in order to permit the Level 1 Appeal process to properly run, it has been
withdrawn.
Information Requests
In response to the Level 1 Appeal, three information requests, each containing two questions, were
issued on January 25, 2012. One was issued to Exelon, one to NERC Standards Process Staff and one to
the Project 2010-07 Standards Drafting Team (SDT) Chair. The information requests and the responses
are appended to this letter which will be posted on the NERC website.
Findings
Timeliness of the Appeal:
The Standard Processes Manual calls for the filing of the appeal within 30 days of the date of the action
purported to cause the direct material adverse impact. The standard with the “line of site change” was
posted on December 14, 2011 and the ballot was finalized on December 23, 2011.
Within the project notice posted on December 14, 2011 it was clearly stated:
“In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO
exemption in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and changed
“RE” to “Regional Entity” in 4.3.1 of FAC-003-X.”
Page 2 of 4
In its response to the first information request Exelon notes its position that the adverse impact did not
occur until the ballot was concluded (unfavorably in Exelon’s view). On this basis Exelon believes its
January 13, 2012 preliminary notice of intent to file an appeal and the January 20, 2012 filing of the
appeal was timely under the SPM. I will consider the filing of this Level 1 Appeal as having been made
timely.
Adverse Impact:
Exelon notes in its response to Information Request 1 that it considers the direct material adverse
impact to be that it would be now subject as a Generator Owner/Generator Operator (GO/GOP) to the
proposed FAC-003-x standard given the line of sight clarification. It is a fair question as to whether
having a standard become applicable to a given entity is truly an adverse impact? If that were the case,
then every registered function would contend the same. I find that it is not an adverse impact for a
subset of Exelon’s nuclear facilities to become subject to the standard. Applicability by itself is not an
adverse impact. The interests of reliability must be served and if the SDT determines that a given set of
circumstances should result in a standard becoming applicable, then that is the technical design. On
the basis of applicability the appeal fails. The SDT in this project was charged specifically with the task
of determining which standards and requirements should be adjusted (and how they should be
adjusted) for applicability to GOs/GOPs.
Procedural Action:
Exelon believes that it did not have ample time to respond to the proposed change. Exelon contends it
was denied the ability to inform the industry. Exelon did provide some information of its efforts to
inform the industry of its beliefs, although apparently it was unpersuasive, given the outcome of the
ballot.
Material Change:
Based on the information request response from the SDT Chair, the SDT believes that the “line of sight”
change it made was clarifying and not material. I agree with Exelon, however that the line of sight
change also had the effect of changing the applicably of the standard based on its construct as Exelon
contends. This is within the technical scope for the SDT under the process. On this basis, I find that
Exelon has made its case that the SPM was not adhered to and that a change impacting applicability
was made between the last successive and recirculation ballot.
Page 3 of 4
Recommended Actions and Options
I refer the issue to the Standards Committee for handling. There are several options to consider:
1. Re-post the standard for a successive ballot and recirculation ballot. Essentially set the clock back and
correctly replay the last steps of the process.
2. Ask the SDT to remove the clarification language from the final standard and go directly to recirculation
ballot.
3. Ask the SDT to redesign the challenged portion of the proposed standard.
I recommend the Standards Committee pursue option 2.
Sincerely,
Herb Schrayshuen
Vice President, Standards and Training
cc: Mr. Gerry. Cauley, President and CEO, NERC
Mr. Ken Peterson, Chair, Board of Trustees Standards Oversight and Technology Committee
Mr. David Cook, General Counsel, NERC
Ms. Holly Hawkins, Associate General Counsel, NERC
Mr. Michael Moon, Director Compliance Operations, NERC
Ms. Laura Hussey, Manager Standards Process, NERC
Ms. Mallory Huggins, GO/TO Standards Drafting Team Advisor, NERC
Mr. Allen Mosher, Chair, Standards Committee
Mr. Louis Slade, Chair, GO/TO Standards Drafting Team
Attachments:
1) Appeal Letter dated January 20, 2012 from Exelon
2) Exelon Response to Data/Information Request
3) Information Request 1 to NERC Standards Process Staff (plus response)
4) Information Request 1 to GO/TO Drafting Team Chair (plus response)
Page 4 of 4
January 20, 2012
Mr. Herb Schrayshuen
Vice President of Standards and Training
North American Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
RE:
Exelon Appeal of FAC-003-3 and FAC-003-X Process
Dear Herb:
Exelon wishes to initiate a Level 1 Appeal of the recent vote on FAC-003-3
(December 1, 2011 draft) and FAC-003-X (December 1, 2011 draft),
Transmission Vegetation Management Program, as part of Project 2010-07,
Generator Requirements at the Transmission Interface. Exelon believes that the
NERC Standards Process Manual was not followed, and that based on the
substantive changes made to both Standards following the Initial Ballot, NERC
should have set the Standards for vote using a Successive Ballot rather than a
Recirculation Ballot.
Exelon voted against these proposed Standards, and while we respect the vote
of the Ballot Body, we believe that the manner in which the Standards were
presented for vote is contrary to the process required by the NERC Standards
Process Manual.
Prior to the Recirculation Ballot, Section 4.3.1, which defines the criteria for
determining which Generation Owners will be covered by the Standards, was
modified to increase the scope and applicability to generator owned overhead
transmission lines by adding the words “or do not have a clear line of sight from
the switchyard fence to the point of interconnection.” FAC-003-3; see also FAC003-X. 1 The Standard Drafting Team’s (“SDT”) explanation for this last minute
addition to Section 4.3.1 is that the addition of the “line of sight reference” merely
clarifies the “exception language based on the intent that was agreed upon by
the stakeholder body.” Sidebar comments to Sections 4.3.1 of FAC-003-3 and
FAC-003-X. The SDT went on to identify the “intent” of the stakeholder body as
follows:
1
The language in Section 4.3.1 of FAC-003-3 and FAC-003-X is similar, but not identical.
(Compare Section 4.3.1 in FAC-003-3 (quoted in body of this letter) to FAC-003-X, which reads
“or does not have a clear line of sight from the switchyard fence to the point of interconnection. . .
.”)) With respect to the language at issue in this appeal, the differences are of no consequence.
Accordingly, references to Section 4.3.1 refer collectively to Section 4.3.1 of FAC-003-3 and FAC003-X.
“’We believe that the one mile length is a reasonable approximation of line
of sight, and that using a fixed starting point (at the fenced area of the
generation station switchyard) eliminates confusion and any discretion on
the part of a Generator Owner or an auditor.’ With the addition of an
explicit line of sight reference here, the SDT believes it has clarified its
original intent.”2
This explanation does nothing more than (1) reiterate the point the SDT has
maintained throughout the entire drafting process, namely that “the one mile
length” of a transmission line “is a reasonable approximation of line of sight,” and
(2) explain that the SDT included a “fixed starting point” (the fenced area of the
generation station switchyard) from which to measure the line to address
stakeholder concerns about excessive Generator Owner discretion and
inconsistent application of the Standard. The stakeholder concerns and the
SDT’s response have absolutely nothing to do with – and certainly do not
express the “intent that has been agreed upon by the stakeholder body” – the
inclusion of “or do not have a clear line of sight from the switchyard fence to the
point of interconnection.” To be clear, the SDT, and even the Ad Hoc Group prior
to the SDT, have always focused on the length of the transmission line (either a
half mile as proposed by the Ad Hoc Group or a mile as proposed by the SDT) as
the basis for determining coverage, the presumption being that up to a certain
distance, the overhead line is in the line of sight at various locations throughout
the Generator Owner’s property and reasonably subject to being managed
through normal day-to-day plant activities. The SDT has not, until the most recent
iteration of the Standards, focused on requiring a “clear” line of sight to “the point
of interconnection.” The requirement that the Generator Owner be able to view
the “point of interconnection” while standing at the switchyard fence is a wholly
new requirement based on new considerations not previously addressed through
stakeholder comments.
A review of the Technical Justification Document, 3 apparently developed prior to
the Initial Ballot (referred to as the “Initial Technical Justification”) supports
Exelon’s position. In that document, the SDT refers to the Ad Hoc Group’s
original thought to exclude from the Standard any transmission lines that was
“less than two spans [long] (generally one half mile from the generator property
line).” 4 The SDT then explained that, “[a]fter reviewing formal comments, the
SDT agreed to revise the exclusion so that it applies to a Facility [transmission
line] if its length is ‘one mile or 1.609 kilometers beyond the fenced area of the
generating station switchyard’ to approximate line of sign [sic] from a fixed
2
Standard FAC-003-X at p. 2 (Draft 3: Dec. 1, 2011); Standard FAC-003-3 at p. 6 (Draft 3: Dec.
1, 2011)
3
From the title, “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” it appears that the document was created on September 30, 2011,
although it appears that the PDF version was created on October 4, 2011.
2011_09_30_Technical_Justification_Document.pdf. In either case, this means the document
was codified prior to the start of the November 9, 2011 Initial Ballot.
4
2011_09_30_Technical_Justification_Document.pdf at p. 3.
point,”5 (the fixed point being the fenced area of the generating station
switchyard). Importantly, the Ad Hoc Group and SDT focused on the length of the
line, with no discussion or evaluation of requiring a “clear” line of sight from the
fence “to the point of interconnection.”
Aside from the fact that the last minute change by the SDT does not reflect
stakeholder intent, it is also technically unsupported. The SDT just added the
requirement for a “clear” line of sight “to the point of interconnection” language
without considering the implications of why such a change was required. While a
specific fixed point may make sense for establishing a starting point from which
to measure distance (the one-mile limitation), it does not when considering a
clear line of sight, especially in light stakeholder comments and the SDT’s
acknowledgment that
in many case, generation Facilities are either (1) staffed and the
overhead portion is within the line of sight or (2) the overhead Facility
is over a paved surface. Stakeholders have generally supported the
rationale exempting these Facilities because incorporating them into FAC003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and
appropriate risk prevention approach. 6
Notably absent from this rationale is any requirement that there be a clear line of
sight from a fixed point; nor is a clear line of sight required when the distance of
the overhead line is short (less than a mile) and the Facilities are staffed on a
daily basis, meaning that the overhead line will be subject to observation by staff,
even if the staff does not have a clear line of sight from a specified fixed point
(the switchyard fence) to the point of interconnection. An example helps illustrate
this point. Some Generator Owner transmission lines come out of the generating
station and take a ‘dog leg’ turn (the line turns at one of the towers). Standing at
the tower, an individual has a clear line of sight to either end of the line (the end
coming out of the station and the end connecting with the point of
interconnection). Since the generating Facility is staffed and the line is within the
Generator Owner’s property line or controlled area, the line can be observed and
maintained by staff in the same manner as any other short distance line with a
“clear” line of sight from the switchyard fence to the point of interconnection.
As illustrated by the preceding discussion, the SDT’s last minute addition of “or
do not have a clear line of sight from the switchyard fence to the point of
interconnection” constitutes a material and significant change in the scope of the
applicability of the Standards to Generator Owners, and it was inappropriate for
NERC to use a Recirculation Ballot. The Standard Process Manual regarding
Recirculation Ballots (pages 19-20) states:
5
2011_09_30_Technical_Justification_Document.pdf at p. 3.
Consideration of Comments Generator Requirements at the Transmission Interface Project
2010-07, p. 1 (emphasis added).
6
Conduct Recirculation (Final) Ballot
(Standard has not Changed Substantively from Prior Ballot)
When the drafting team has reached a point where it has made a good
faith effort at resolving applicable objections, the team shall conduct a
recirculation ballot. In the recirculation ballot, members of the ballot pool
shall again be presented the proposed standard (that has not been
significantly changed from the previous ballot) along with the reasons
for negative votes, the responses, and any resolution of the differences.
An insignificant revision is a revision that does not change the
scope, applicability, or intent of any requirement and includes but is
not limited to things such as correcting the numbering of a
requirement, correcting the spelling of a word, adding an obviously
missing word, or rephrasing a requirement for improved clarity.
Where there is a question as to whether a proposed modification is
“substantive” the Standards Committee shall make the final determination.
There is no formal comment period concurrent with the recirculation ballot
and no obligation for the drafting team to respond to any comments
submitted during the recirculation ballot.
(Emphasis added.)
Regardless of whether the SDT believed that its addition of the language at issue
here clarified the intent of the stakeholder body, using the Recirculation Ballot for
the Standards was not warranted or allowed by process. An unarticulated intent
of the stakeholder body cannot serve as the basis for a substantive change to the
Standard. More importantly, the language added by the SDT clearly changed the
scope and applicability of the Standard, by drawing in Generator Owners that
would have otherwise been excluded from the Standards, namely those
Generator Owners with transmission lines less than a mile long that will now be
covered by the Standard because some shorter distance of its line is not clearly
visible from the switchyard fence to the point of interconnection. The SDT’s
presentment of this change through a Recirculation Ballot deprived Exelon (and
possibly others) of having its comments considered by the SDT and the SDT
answer on the record for consideration by the Ballot Body in accordance with the
requirements of a Successive Ballot. You can read Exelon’s comments on the
Recirculation Ballot at:
https://standards.nerc.net/VoterComment.aspx?VoteGUID=8801b661-a474-4f54b14a-4cfe644bdaa6.
Please let me know if you have any further questions.
Best regards,
Steven T. Naumann
Vice President, Wholesale Market Development
Federal Regulatory Affairs & Public Policy, Exelon Corporation
Exekn.
Business Services
Company
4300 Winfield Road
Warrenville. Illinois 60555
Tamra.Domeyer@exeloncorD.com
(630) 657-3753
Via email [herb.schrayshuen@nerc.netl
February 3, 2012
Mr. Herb Schrayshuen
Vice President of Standards and Training
North American Reliability Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
Re:
Exelon Corporation Response to Data/Information Request
Exelon Level 1 Appeal of FAC-003-31X in Project 2010-07
Dear Mr. Schrayshuen:
As requested, enclosed is the Exelon Corporation Response to Data/Information Request
in support of Exelon’s Level 1 Appeal of FAC-003-3/X in Project 20 10-07.
If you require additional information or you have any questions, please let me know.
Very truly yours,
u 6oK47’t2
1
k
444
Jm
Tamra Domeyer
Assistant General Counsel
End.
cc:
Steven T. Naumann
Datallnformation Request
Exelon Level 1 Appeal of FAC-003-3/X in Project 2010-07
RESPONSE OF EXELON COPORATION TO DATA/INFORMATION REQUEST
Summary of Appeal: Please refer to Exelon’s January 20, 2012 letter addressed to Herb
Schrayshuen, Vice President of Standards and Training, for a more detailed discussion of the
basis for Exelon’s Level 1 Appeal of the FAC-003-31X’ Recirculation Ballot vote. Specifically,
Exelon takes issue with the results of the Recirculation Ballot for FAC-003-3/X and acceptance
of the vote. The Standard Drafting Team’s (“SDT”) last minute addition of language to Section
4.3.1 (“or do not have a clear line of sight from the switchyard fence to the point of
2 (referred to as the “clear line of sight” language)) that significantly broadens
interconnection”
the scope of applicability to Generation Owners necessitated submission of the revised Standards
for comment and a Successive Ballot. Exelon maintains further that the SDT’s revision to
Section 4.3.1 constitutes a substantive and material change to the scope, applicability, and intent
of the requirement that adversely impacts Exelon.
Request 1: When and through what means did Exelon representative(s) first become aware of
the modifications (line of sight language) to the FAC-003-3/X standard which they believe were
substantive?
Response to Request 1: Exelon first became aware of and focused on the SDT’s substantive
modification to Section 4.3.1 of FAC-003-3/X on December 20, 201 i,
3 when its subject matter
experts held an internal conference call to review and discuss the Recirculation Ballot for FAC
003-3/X. During that review, Exelon’s subject matter experts were surprised to discover what
they determined to be a substantive modification to Section 4.3.1, since the Standards
Announcement for the Initial Ballot results clearly committed to post any substantive changes
“for a parallel 30-day comment period and successive ballot.”
4
References to FAC-003-3/X are to FAC-003-3 (Draft 3, December 1, 2011) and FAC-003-X (Draft 3, December 1,
2011), specifically Section 4.3.1 of each draft Standard. The language in Section 4.3.1 of each Standard is similar,
but not identical. With respect to the language at issue in this appeal, the slight differences in language in Section
4.3.1 of each draft Standard are of no consequence.
2
FAC-003-3; Section 4.3.1 of FAC-003-X reads as follows:
switchyard fence to the point of interconnection
“or does not have a clear line of sight from the
NERC issued a Standards Announcement of the Recirculation Ballot on December 14, 2011. Although Exelon
received the Standards Announcement, it did not identify the substantive modification to Section 4.3.1 until the
internal conference call on December 20, 2011.
Standards Announcement, Project 2010-07 Generator Requirements at the Transmission Interface, Initial Ballot
Results, p.1.
Exelon Corporation
Level 1 Appeal of FAC-003-31X in Project 20 10-07
Response to Data/Information Request
Page 2 of 5
Exelon recognized that the proposed modification to FAC-003-3/X would have no impact on
Exelon unless the Standard(s) received the requisite votes for approval through the Recirculation
Ballot. On December 21, 2011, Exelon advised PJM and the Midwest ISO of Exelon’s
determination that the SDT’s modification of FAC-003-3/X was not minor, changed the scope of
applicability, and should be submitted through a Successive Ballot. Exelon also challenged the
technical basis (lack thereof) for the SDT’s last minute addition of the “clear line of sight”
language to Section 4.3.1 and advised PJM and Midwest ISO of its intention to vote “negative”
in the Recirculation Ballot. Exelon invited PJM and Midwest ISO to forward Exelon’s comments
to various PJM and Midwest ISO members. On the same day (December 21), Exelon received a
response from Louis Slade, writing “[a]s Vice Chair of the SDT,” expressing his disappointment
with Exelon’s decision to vote negative and disagreement with Exelon’s position. (See
Attachment 1, email from Exelon, sent on December 21, 2011 at 9:34 a.m., and response of SDT
Vice Chair sent on December 21, 2011 at 2:42 p.m.) The Vice Chair of the SDT subsequently
requested that PJM distribute his response to PJM members. Neither the SDT nor NERC took
any action to remove FAC-003-3/X from the Recirculation Ballot and submit it for comments
and a Successive Ballot.
Exelon collectively
5 voted “Negative” in the Recirculation Ballot(s) for FAC-003-3/X. In its
comments in support of its negative vote, Exelon noted, among other things, that the
modification constituted a substantive change that should have been presented through a
Successive Ballot. The Recirculation Ballot closed on December 23, 2011. On January 3, 2012,
NERC issued a Standards Announcement with the Recirculation Ballot Results, including the
approval of Standard FAC-003-3/X. With that announcement, and in the absence of an appeal,
NERC conclusively foreclosed consideration of Exelon’s comments and shut the door on an
opportunity for a Successive Ballot for FAC-003-3/X. On January 17, 2012, Steven T. Naumann,
Vice President, Wholesale Market Development for Exelon, discussed this matter with Herb
Schrayshuen, NERC’s Vice President of Standards and Training. On January 18, Mr. Naumann
sent an e-mail to Mr. Schrayshuen informing him that Exelon would be filing a level 1 appeal
and that the formal appeal would be sent by the close of business on January 20. (See
Attachment 2). Exelon subsequently submitted its Level 1 Appeal on January 20, 2012, within
thirty days of the close of the Recirculation Ballot on December 23, 2011 and the January 3,
2012 announcement of the Recirculation Ballot results.
Respondent Identity: Tamra Domeyer, Assistant General Counsel, Exelon Business Services
Company
Date: February 3, 2012
Exelon voting ballot body members for the (12/14/2011 12/23/Il) Recirculation Ballots of Project 2010-07 for
FAC-003-3 and FAC-003-X were PECO Energy, CornEd, Exelon Nuclear, and Exelon Power Team.
—
Exelon Corporation
Level I Appeal of FAC-003-31X in Project 20 10-07
Response to Data/Information Request
Page 3 of 5
Request 2: Specifically identify the “direct material” or adverse impact the change made to
FAC-003-3/X between the successive and recirculation ballot has on Exelon?
Response to Request 2: The last minute modification to Section 4.3.1 has a material, adverse
impact on Exelon by changing the scope and applicability of the Standard. Specifically, of the
seventeen active nuclear generating units at ten different sites owned and operated by Exelon
affiliate Exelon Generation Company, LLC Exelon Nuclear, none satisfied the applicability
criteria under earlier versions of FAC-003-3/X,
6 and as such, none of Exelon’s nuclear
generating units would have been subject to the FAC-003-3/X requirements. The last minute
addition of the “clear line of sight” language to the FAC-003-3/X Standards that were approved
in the December 23, 2011 Recirculation Ballot changes Exelon Nuclear’s status from a
Generator Owner for which the Standards are “not applicable” to a Generator Owner for which
the Standards are potentially “applicable.” Exelon Nuclear has not finished its investigation at
each of its ten sites to conclusively determine which of its seventeen generating units might now
be subject to the FAC-003-31X requirements. The point is that by adding the “clear line of sight”
requirement, the SDT has now removed Exelon Nuclear from the group of Generator Owners not
subject to FAC-003-3/X requirements and placed it squarely in a group potentially subject to the
requirements of FAC-003-3/X.
—
A determination that the current FAC-003-3/X Standards may now be applicable to even one of
Exelon Nuclear’s generating units has a material, adverse impact on Exelon Nuclear. Vegetation
management programs developed to implement NERC Standard FAC-003 are expensive and
time consuming and require specialized skills. In addition, compliance with each NERC
Standard requires substantial resources, time, and attention. While Exelon certainly supports and
understands the need for reliability standards and complies with all NERC Reliability Standards
6
FAC-003-31X was submitted for vote on two occasions: as an Initial Ballot from November 9 through
November 18, 2011 and as a Recirculation Ballot from December 14 through December 23, 2011. The
version of FAC-003-3/X (Draft 2) submitted to the Initial Ballot defined Generation Facilities that would
be subject to FAC-003 requirements as “Overhead transmission lines that extend greater than one mile or
1.609 kilometers beyond the fenced area of the generating switchyard
(FAC-003-3 (Draft 2,
September 29, 2011); FAC-003-X (Draft 2, August 31, 2011) (“Generator Owner that owns an overhead
transmission line(s) that extends greater than one mile or 1.609 kilometers beyond the fenced areas of the
generating station switchyard up to the point of interconnection with the Transmission Owner’s Facility.
(Section 4.3.1)) Earlier versions of the FAC-003-3/X Standard contained similar verbiage focusing
solely on the length of the transmission line as the trigger for determining whether a Generator Owner
would be subject to the FAC-003-3/X (Draft 2) requirements. The generator lines that Exelon Nuclear
owns are less than a haif mile long for each nuclear generating unit, and thus, FAC-003-3/X (Draft 2)
.“
requirements would not have applied to any of Exelon Nuclear’s generating units.
Exelon Corporation
Level 1 Appeal of FAC-003-3/X in Project 2010-07
Response to Data/Information Request
Page 4 of 5
applicable to it regardless of the cost, the public policy concerns that warrant application of a
NERC Standard to a specific registered entity namely reliability of the bulk electric system
simply do not exist here. As the SDT aptly noted, “the transmission elements and facilities
owned and operated by Generator Owners are most often not part of the integrated grid” and
—
—
as such have little, if any, measurable effect on the overall reliability of the BES. In fact,
registering a Generator Owner or Generator Operator as a Transmission Owner or
Transmission Operator may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s attention from the operation of the equipment that actually
produces electricity the generation equipment itself.
7
—
The same can be said here requiring Exelon Nuclear to implement and maintain a formal
NERC vegetation management program for short distances of lines (each of Exelon Nuclear’s
generator lines is less than a half mile long) that are within Exelon Nuclear’s controlled property,
in the clear line of sight from various locations throughout its property, and reasonably subject to
being managed through normal day-to-day plant activities and surveillances conducted by any
number of its employees staffed to operate the plant round the clock each and every day,
8 adds
little to no value to the reliability of the bulk electric system and is not a good use of the
resources of the Generation Owner/Operator, the Regional Entity or the ERO.
—
Exelon’s position is entirely consistent with the SDT’s findings that:
in many cases, generation Facilities are either (1) staffed and the overhead portion is
within line of sight or (2) the overhead Facility is over a paved surface. Stakeholders
have generally supported the rationale exempting these Facilities because incorporating
them into FAC-003 would offer no reliability benefit. The SDT and industry comments
support the position that these qualifiers represent a reasonable and appropriate risk
prevention approach.
9
Many of Exelon Nuclear’s generator transmission lines travel over paved surfaces, with no
vegetation at all on the ground under the lines. Nevertheless, if the “clear line of sight”
requirement stands, Exelon Nuclear will be required to assess whether it has a “clear line of sight
from the switchyard fence to the point of interconnection.” Aside from the fact that the meaning
Project 2010-07: Generator Requirements at the Transmission Interface, Background Resource Document, pp. 2, 3.
8
All operating nuclear generating units are staffed continuously and must maintain minimum staffing in accordance
with site specific licensing requirements of the Nuclear Regulatory Commission.
Consideration of Comments, Generator Requirements at the Transmission Interface, Project 2010-07, p. 1
(emphasis added).
Exelon Corporation
Level 1 Appeal of FAC-003-3/X in Project 20 10-07
Response to Data/Information Request
Page 5 of 5
of “switchyard fence” is unclear,’
0 there is no basis for requiring a clear line of sight from the
switchyard fence to the point of interconnection. The premise of the SDT in focusing on the
length of the generator transmission line has always been that the relatively short length of the
line (up to a mile) constitutes a proxy for the line of sight, since the area traversed by the line is
relatively short, allowing the Generator Owner to have a line of sight from any number of
vantage points within the Generator Owner’s controlled area and property. Moreover, to the
extent the entire length of the line travels over paved surfaces or structures, any barriers or
obstacles to a clear line of sight will not be caused by vegetation, as discussed in FAC-003-3/X
but, rather, by equipment, components, or structures. Clearance between generator lines and
structures is already covered in other NERC Standards and is the subject of a recently issued
NERC Alert.” And, even for those lines that do travel over areas of vegetation, the regular
monitoring and surveillance by Exelon Nuclear staff of the areas over which the lines travel
provides reasonable assurance of protection from vegetation related events.
Referring to the example noted in Exelon’ s January 20, 2011 Level 1 Appeal letter, at another
Exelon Nuclear location, a transmission line coming out of the generating station takes a “dog
leg” turn (the line turns at one of the towers). Standing at the tower, an individual has a clear
line of sight to either end of the line (the end coming out of the station and the end connecting
with the point of interconnection). Since the generating Facility is staffed and the line is within
Exelon Nuclear’s property and controlled area, the line can be observed and maintained by
Exelon Nuclear’s round the clock staff in the same manner as any other short distance line with a
“clear line of sight from the switchyard fence to the point of interconnection.”
Respondent Identity: Tamra Domeyer, Assistant General Counsel, Exelon Business Services
Company
Date: February 3, 2012
10
Does switchyard fence mean the “generating switchyard” fence, as referenced in the beginning of the first
sentence in Section 4.3.1 (“overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard”) or the Transmission Owner switchyard fence that surrounds the
switchyard where the generation transmission line interconnects with the transmission system? Exelon Nuclear’s
generating stations do not have generating switchyards; if “switchyard fence” refers to the generating switchyard,
there is no fence from which Exelon Nuclear can determine whether it has a “clear line of sight.”
‘
FAC-008, FAC-009, and NERC Alert R-2010-lO-07-01, Consideration of Actual Field Conditions in
Determination of Facility Ratings.
From: pjm-rsacs-bounces+alison.mackellar=exeloncorp.com@lisI:s.pjm.com [mailto:pjm-rsacs
bounces+alison.mackellar=exeloncorp.com@Iists. pjm .com] On Behalf Of brownp@pjm.com
Sent: Thursday, December 22, 2011 8:01 AM
To: pjm-rsacs©lists.pjm.com
Subject: [Pjm-rsacs] FW: FW: REVIEW Project 2010-07 Generator Requirements at the
Transmission Interface Negative Voting Position
-
The SDT’s response to Exelon’s comments, for your consideration.
Patrick Brown
Manager, NERC and Regional Coordination
PJM Interconnection
Phone: 610-666-4597
Cell: 610-908-9262
m.com
From: Louis Slade [mailto: louis.slade@dom.com]
Sent: Thursday, December 22, 2011 8:56 AM
To: Brown, Patrick
Subject: RE: [Pjm-rsacs] FW: REVIEW Project 20 10-07 Generator Requirements at the
Transmission Interface Negative Voting Position
-
Would you consider also distributing this?
From: Louis Slade (Services 6)
Sent: Wednesday, December 21, 2011 2:42 PM
To: ‘john.bee@exeloncorp.com’
Subject: FW: REVIEW Project 2010-07 Generator Requirements at the Transmission Interface
Exelon Comments
-
-
Dear Mr. Bee,
As Vice Chair of the SDT, I am writing to express my personal disappointment that Exelon plans
to change its vote. The team has worked very hard to strike a reasonable balance in applying
additional reliability standards to GO/GOPs who own or operate all, or a portion of, a sole use
facility used to interconnect generators to the integrated transmission system. Throughout our
efforts, we have continually cited the need to apply FAC-003 to such a facility while trying to
‘carve out’ those that didn’t represent a risk to the reliability of the integrated transmission
system. We reasoned that exempting lines of short length at generating facilities was justified
because they would likely be located within sight of the personnel at that generating facility.
The Background Resource raper from our l posting stated “Revise FAC-003 so that it
applies to Generator Owners that own a Facility that extends greater than one half mile beyond
the fenced area of the switchyard, generating station or generating substation (up to the point
of interconnection with the Transmission system). (See accompanying draft standards FAC-003X and FAC-003-3.)
Attachment 1
o The drafting team elected to use the half-mile qualifier in its latest proposed changes.
The GOTO Ad Hoc Group had originally proposed something similar, but their proposed
criterion was a length of “two spans (generally one half mile from the generator
property line).” The drafting team elected to use only the half-mile qualifier because it
has been supported by industry comment and is clearer than referencing both two
spans and the half-mile length. This distance is within the Generator Owner’s line of
sight and could be visually monitored for vegetation conditions on a routine basis.
Beyond the distance of one half mile, a vegetation management program is necessary to
manage the Right-of-Way.”
The SDT received comments during this posting that the requirements allowed the GO
to determine where to begin measuring the length of its facility from either; (a) the fenced area
of the switchyard (b) the generating station or (c) the generating substation. As the SOT
discussed these comments we agreed that this was not our intent and agreed that a more
clearly defined beginning point for the measurement was desired. We made subsequent
changes to the next drafts posted for comments.
Again, we explained our rationale in the Technical Justification document posted, stating
“After reviewing formal comments, the SDT agreed to revise the exclusion so that it applies to a
Facility if its length is “one mile or 1.609 kilometers beyond the fenced area of the generating
station switchyard” to approximate line of sign from a fixed point. Other than revising this
exclusion, the SOT applied the same criteria to the Generator Owner as applies to the
Transmission Owner
The SOT received many comments during the next posting stating that it did not
provide technical justification for the exemption. Given that we have cited line of sight in our
reference documents and in our responses, the only solution we found reasonable was to
include it in the actual language of the reliability standard itself.
As we stated in the Technical Justification document posted with our most recent
changes “The SDT and most stakeholders agree with the Ad Hoc Group recommendation that
FAC-003 be applicable to Generator Owners that own a generation interconnection Facility if
that Facility contains overhead conductors. The Ad Hoc Group originally excluded such a Facility
from this requirement if its length is less than two spans (generally one half mile from the
generator property line). The SOT agrees with that intended exclusion in principle; as it discusses
in the document titled “Technical Justification Project 2010-07 Generator Requirements at the
Transmission Interface,” the SDT recognizes that in many cases, generation Facilities are (1)
staffed and the overhead portion is within line of sight or (2) the overhead Facility is over a
paved surface. Stakeholders have generally supported the rationale for exempting these
Facilities because incorporating them into FAC-003 would offer no reliability benefit.”
While I respect and value your opinion, it is my belief the SOT has done the best it can to include
language that allows for an exemption while insuring that risk to the integrated transmission
system is minimized. Oue to the virtually unlimited configurations, topologies, etc. of these
facilities, it is impossible to create a clear and unambiguous standard that will accommodate
each facility to the owners satisfaction or, for that matter, to that facility’s specific potential to
adversely impact reliability of the integrated transmission system.
The SDT has chosen language that it believes has the best chance of meeting the stated purpose
of the FAC-003 standard, being measurable to both the registered entity and the auditor and
reducing compliance burden without a commensurate improvement in reliability.
These comments are my own and are not to be taken as those of either the SDT members nor
my employer.
Sincerely,
Louis Slade, Jr.
From: pjm-rsacs-bounces+louis.slade=dom.com@lists.pjm.com [mailto: pjm-rsacs
bounces+louis.slade=dom.com@lists.pjm.com] On Behalf Of brownp@pjm.com
Sent: Thursday, December 22, 2011 8:51 AM
To: pjm-rsacs©lists.pjm.com
Subject: [Pjm-rsacs] FW: REVIEW Project 2010-07 Generator Requirements at the Transmission
Interface Negative Voting Position
Importance: High
-
FYI- some comments from Exelon regarding the changes made to Project 2010-07 prior to the
recirc ballot.
Patrick Brown
Manager, NERC and Regional Coordination
PJM Interconnection
Phone: 610-666-4597
Cell: 610-908-9262
brownp@pim.com
From: john.bee@exeloncorp.com [mailto:john.bee©exeloncorp.com]
Sent: Wednesday, December 21, 2011 9:34 AM
To: MKnox@midwestiso.org; Brown, Patrick
Subject: REVIEW Project 2010-07 Generator Requirements at the Transmission Interface
Negative Voting Position
Importance: High
-
Marie and Patrick,
Yesterday SMEs from the Exelon companies review the proposed changes to Project 2010-07
Generator Requirements at the Transmission Interface related to the recirculation ballot. We
noticed what we consider a significant change to FAC-003-3 Requirement with the addition of the
text bolded and underlined below:
4.3.1. Generator Owner that owns an overhead transmission line(s) that extends greater than one
mile or (1.609 kilometers) beyond the fenced area of the generating station switchyard up to
the point of interconnection with a Transmission Owner’s Facility or does not have a
clear line of sight from the switchyard fence to the point of interconnection and
is operated at 200 kV and above, and any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
Exelon plans to change its affirmative voting position to negative based on the additional
text. First we don’t feel this was a minor change and feel that that the ballot should
have been a successive ballot not a recirculation ballots. Second we feel the
additional text is ambiguous adds unnecessary restrictions in assessing criteria
applicability. Exelon feels that the SDT has not provided adequate technical
justification as to why a single line of sight (linearly from the switchyard fence to
the point of the interconnection) is the only acceptable vantage point from which to
verify the condition of a generator interconnection. We are currently working on
comments to be submitted with our negative ballot and plan to be completed by
12:00 today. Because of the upcoming holidays and the fact that the ballot pooi will
close on 12/23, I am attaching our working draft comments. Please feel free to pass
this on to members of your PJM RSACS and the MISO Standards Collaboration
members if you see fit.
Happy Holidays,
jo/ifl
Bee
Exelon Transmission Strategy & Compliance
2 Lincoln Center, Oak Brook Terrace IL. 60181
(630) 576-6925 Phone
(630) 297-3457 Cell Phone
john.bee @ exeloncorp.com
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If you have received this e-mail in enor, please notify the sender immediately and
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**************************************************
CONFIDENTIALITY NOTICE: This electronic message contains information which
may be legally confidential andJor privileged and does not in any case represent a firm
ENERGY COMMODITY bid or offer relating thereto which binds the sender without an
additional express written confirmation to that effect. The information is intended solely
S
Ct%.’
1
tt
S
Domeyer, Tamra:(GenCo)
From:
Naumann, Steven T.:(BSC)
Sent:
Wednesday, January 18, 2012 12:10 PM
To:
herb.schrayshuen@nerc.net
Cc:
Domeyer, Tamra:(GenCo)
Subject: Appeal of Project 2010Herb:
To follow up on our discussion yesterday, Exelon intends to file a formal Level 1 Appeal of FAC-003-3/FAC-003-X
balloted as part of Project 2010-7. We will send you the formal appeal by close of business on Friday, January
20. Thanks for discussing this issue with me and please let me know if you need further information.
Steve
Steven T. Naumann
Vice President Wholesale Market Development
Federal Regulatory Affairs & Public Policy, Exelon Corporation
Phone: 312.394.2807
FAX: 312.394.8997
Mobile: 708.404.6829
E-Mail: steven.naumann © exeloncorp.com
Attachment 2
2/3/2012
Data/Information Request
Exelon Level 1 Appeal of FAC-003-3x in Project 2010-07
Request 1–Identify in which steps of the standards development process, and provide evidence to
support, that Exelon Comments were made visible to the other industry participants in the FAC-003-x
ballot.
Response 1:
The attached document summarizes the process steps taken in developing FAC-003-X and FAC-003-3
and the comments pertaining to FAC-003 submitted by Exelon at each step. Each time comments are
collected in a formal or informal comment period, a “Comments Received” document is posted to the
project webpage within a few business days of the comment period closing. In addition, the comments
are posted, along with the drafting team’s response to the comments (in summary form for informal
comment periods and in detail for formal comment periods) before the next process step is initiated. A
full record of all postings is available on the project webpage.
Respondent Identity: Laura Hussey, Standards Process Manager
Date:
1/26/2012
Request 2-Identity the participants and the meeting or calls during which the decision that the
standards changes (regarding line of sight) referenced in Exelon’s complaint were not substantive.
Provide any contemporaneous documents generated from the meeting or call.
Response 2:
The decision to allow FAC-003 to proceed to recirculation ballot was carefully considered by NERC
Standards Process staff (Laura Hussey, Maureen Long) in consultation with the drafting team
coordinator (Mallory Huggins) and leadership (Louis Slade and Scott Helyer). There were no conference
calls or face-to-face meetings (none of the above-mentioned are collocated, and one member of the
drafting team leadership was on vacation during the decision so was only available remotely).
A complete record of the emails exchanged is attached.
Respondent Identity: Laura Hussey, Standards Process Manager
Date: 1/26/2012
Data/Information Request
Exelon Level 1 Appeal of FAC-003-3x in Project 2010-07
Request 1 – Outline the basis upon which the industry participants in the Standards Drafting Team
concluded that the changes Exelon complains about in its Level 1 appeal were not substantive.
Response 1 –The SDT agreed that, based upon stakeholder comments received and recommendations
from FERC staff observers, it should better define exemption for Generator Owners in Applicability
Section 4.3.1. The goal was to ensure that the explicit language of the exemption included the clear line
of sight justification for exempting “qualifying” lines from applicability. To support its changes, the SDT
then reviewed its past work, as well as that of the Ad Hoc Team. It justified its changes between the
successive ballot and the recirculation ballot based on the following:
Ad Hoc Report – P. 15 of the report states “The rationale for the selection of the two-span criteria is that
this distance is in the generator operator’s line-of-sight and as such could be visually monitored for
vegetation conditions on a routine basis, and beyond which distance a vegetation management program
would be necessary for the Right-of-Way” (emphasis added).
Documents produced by the Project 2010-07 SDT and posted during stakeholder comment periods
•
The background resource document (white paper), posted with the revised versions of FAC-003
for comment in June 2011, states: “The drafting team elected to use only the half-mile qualifier
because it has been supported by industry comment and is clearer than referencing both two
spans and the half-mile length. This distance is within the Generator Owner’s line of sight and
could be visually monitored for vegetation conditions on a routine basis. Beyond the distance of
one half mile, a vegetation management program is necessary to manage the Right-of-Way”
(emphasis added).
•
The technical justification document, which was posted with the revised versions of FAC-003 for
comment in October 2011, states:“After reviewing formal comments, the SDT agreed to revise
the exclusion so that it applies to a Facility if its length is “one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard” to approximate line of sign from a fixed
point” (emphasis added).
Based upon these documents, the SDT believes the technical justification for the exemption has existed
from the beginning of this effort. The intent – that the exemption be for generator interconnection
Facilities within the generator’s line of sight – has been communicated clearly all along, but until the
change between the successive ballot and the recirculation ballot, that intent was implicit rather than
explicit. After extensive discussion, the SDT agreed with some comments and with the
recommendations of FERC staff observers that it would be better if the line of sight language was
included in the standard itself rather than only in supporting documentation. For this reason, the SDT
modified the language in Applicability Section 4.3.1 of both versions of FAC-003 and considered the
change clarifying – and thus non-substantive – based on its communications of its intent throughout the
standard development process. At this point, the SDT passed the standards along to NERC staff for a
final determination of whether the proposed FAC-003 changes were appropriate for recirculation ballot.
It is also worth noting that during the recirculation ballot in December 2011, Exelon raised its concern
via email to PJM and MISO listservs. SDT Chair Louis Slade was afforded the opportunity to respond to
this concern for the benefit of all those on the distribution lists, and the high approval ratings on FAC003-3 and FAC-003-X (85.38% and 85.03%, respectively) indicate that other entities found Louis’s
explanation of the non-substantive nature of the FAC-003 changes satisfactory.
Respondent Identity: Louis S. Slade, Jr.
Date: Jan. 26, 2012
Request 2 – Identity the participants and the meeting or calls during which the decision that the
standards changes (regarding line of sight) referenced in Exelon’s complaint were not substantive.
Provide any contemporaneous documents generated from the meeting or call.
Response 2 – As identified in the meeting notes from the November 30-December 1, 2011 SDT meeting
in Washington, DC (posted on NERC’s website), participants during the original discussion were: SDT
members Louis Slade, Scott Helyer, Sam Dwyer, Steve Enyeart, Bob Goss, and Rick Terrill; observers
Ellen Oswald and John Seelke; FERC staff Susan Morris and Stephanie Schmidt; and NERC staff Mallory
Huggins. Later email discussions included the full SDT, with major participation from Louis Slade and
Sam Dwyer, as indicated in the attached emails.
Respondent Identity: Louis Slade
Date: Jan. 26, 2012
From:
To:
Subject:
Date:
Attachments:
Mallory Huggins
grti_sdt
FAC-003 Exception Language
Tuesday, December 13, 2011 3:38:34 PM
FAC-003-3_redline to last posted.doc
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
From:
To:
Cc:
Subject:
Date:
Louis Slade
Mallory Huggins; "SDwyerIV@ameren.com"
"SHelyer@tnsk.com"
Re: FAC-003 Exception Language
Tuesday, December 13, 2011 5:53:26 PM
Ok by me
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 05:49 PM
To: Louis Slade (Services - 6); 'SDwyerIV@ameren.com'
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
I think the “or” can work – it’s the same as the (a)/(b) structure we originally had, but without the
(a) and (b). We could go the route you propose below, but I think the cleaner way (as in, we have
to add the least amount of text) to do it is how we have it now.
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:47 PM
To: 'SDwyerIV@ameren.com'; Mallory Huggins
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
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From:
To:
Cc:
Subject:
Date:
Dwyer IV, Samuel J
Mallory Huggins
scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:27:05 PM
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
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hereby notified that any dissemination, distribution or copying of this communication is
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of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Mallory Huggins
"Louis Slade"; "SDwyerIV@ameren.com"
"SHelyer@tnsk.com"
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:49:00 PM
I think the “or” can work – it’s the same as the (a)/(b) structure we originally had, but without the
(a) and (b). We could go the route you propose below, but I think the cleaner way (as in, we have
to add the least amount of text) to do it is how we have it now.
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:47 PM
To: 'SDwyerIV@ameren.com'; Mallory Huggins
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
information is prohibited and may be unlawful. If you have received this electronic
transmission in error, please reply immediately to the sender that you have received the
message in error, and delete it. Thank you.
From:
To:
Cc:
Subject:
Date:
Louis Slade
"SDwyerIV@ameren.com"; Mallory Huggins
"SHelyer@tnsk.com"
Re: FAC-003 Exception Language
Tuesday, December 13, 2011 6:42:44 PM
Agree that we want to go to recirc. So don't make changes that prohibit doing so
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 06:31 PM
To: Louis Slade (Services - 6); 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
Louis –
We did, so either is fine with me.
Mallory – you might want to try Louis' simpler words below first. If that doesn't fly, try the
switchyard wording if that's what we need to put this out for recirc.
Louis – Is that OK with you? I'd hate to see us lose our momentum at the last minute and I don't
think this is a deal-breaker – at least in my opinion.
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:01 PM
To: Dwyer IV, Samuel J; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
One thing troubles me. Didn't we have comments in this or past that stated some generating
facilities don have switch yards? If so, maybe just say clear line of sight between GSU and point of
interconnection
From: Louis Slade (Services - 6)
Sent: Tuesday, December 13, 2011 05:47 PM
To: 'SDwyerIV@ameren.com' ; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
information is prohibited and may be unlawful. If you have received this electronic
transmission in error, please reply immediately to the sender that you have received the
message in error, and delete it. Thank you.
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Dwyer IV, Samuel J
Louis Slade; Mallory Huggins
"SHelyer@tnsk.com"
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 6:31:31 PM
Louis –
We did, so either is fine with me.
Mallory – you might want to try Louis' simpler words below first. If that doesn't fly, try the
switchyard wording if that's what we need to put this out for recirc.
Louis – Is that OK with you? I'd hate to see us lose our momentum at the last minute and I don't
think this is a deal-breaker – at least in my opinion.
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:01 PM
To: Dwyer IV, Samuel J; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
One thing troubles me. Didn't we have comments in this or past that stated some generating
facilities don have switch yards? If so, maybe just say clear line of sight between GSU and point of
interconnection
From: Louis Slade (Services - 6)
Sent: Tuesday, December 13, 2011 05:47 PM
To: 'SDwyerIV@ameren.com' ; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
information is prohibited and may be unlawful. If you have received this electronic
transmission in error, please reply immediately to the sender that you have received the
message in error, and delete it. Thank you.
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
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From:
To:
Cc:
Subject:
Date:
Mallory Huggins
"Dwyer IV, Samuel J"
scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:33:00 PM
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Louis Slade
"SDwyerIV@ameren.com"; Mallory Huggins
"SHelyer@tnsk.com"
Re: FAC-003 Exception Language
Tuesday, December 13, 2011 5:47:15 PM
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which
may be legally confidential and/or privileged and does not in any case represent a
firm ENERGY COMMODITY bid or offer relating thereto which binds the sender
without an additional express written confirmation to that effect. The information is
intended solely for the individual or entity named above and access by anyone else
is unauthorized. If you are not the intended recipient, any disclosure, copying,
distribution, or use of the contents of this information is prohibited and may be
unlawful. If you have received this electronic transmission in error, please reply
immediately to the sender that you have received the message in error, and delete
it. Thank you.
From:
To:
Cc:
Subject:
Date:
Dwyer IV, Samuel J
Louis Slade; Mallory Huggins
"SHelyer@tnsk.com"
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:59:52 PM
Louis –
I think this will work. We could incorporate your wording, but I still end up with more words than
Mallory's last suggestion. This is why I hate stringing phrases together with "and" or "or", but we
don't have a choice if we want the recirc ballot.
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 4:53 PM
To: 'Mallory.Huggins@nerc.net'; Dwyer IV, Samuel J
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
Ok by me
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 05:49 PM
To: Louis Slade (Services - 6); 'SDwyerIV@ameren.com'
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
I think the “or” can work – it’s the same as the (a)/(b) structure we originally had, but without the
(a) and (b). We could go the route you propose below, but I think the cleaner way (as in, we have
to add the least amount of text) to do it is how we have it now.
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:47 PM
To: 'SDwyerIV@ameren.com'; Mallory Huggins
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
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of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
information is prohibited and may be unlawful. If you have received this electronic
transmission in error, please reply immediately to the sender that you have received the
message in error, and delete it. Thank you.
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
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From:
To:
Cc:
Subject:
Date:
Mallory Huggins
"Dwyer IV, Samuel J"
scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:18:00 PM
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Dwyer IV, Samuel J
Mallory Huggins
Louis Slade; "SHelyer@tnsk.com"
RE: FAC-003 Exception Language
Wednesday, December 14, 2011 9:33:18 AM
Mallory –
You did a good job with the ramblings from Louis and me. Thanks for the great last minute effort!
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Wednesday, December 14, 2011 8:20 AM
To: Louis Slade; Dwyer IV, Samuel J
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
Louis, you were right that there were some folks concerned because their Facilities didn’t have
switchyards (and I raised that same concern when chatting with Laura about it), but I made a game
time decision and rationalized that (1) leaving the switchyard language in there ensures that we
change as little as possible between the last posting and now, and (2) we did get 85% support for
our changes, so I feel comfortable sticking with that language if we must. I wrapped up everything
last night and sent it on for posting, which will hopefully happen before noon. Here’s the
rationalization language I added both in a text box within the two FAC-003s, and in some of the
other docs:
With the line of sight reference in 4.3.1, the SDT simply seeks to clarify the exception
language based on the intent that has been agreed upon by the stakeholder body. In its
Consideration of Comments report from the last formal comment period, which ended on
July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable
approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a
Generator Owner or an auditor.” With the addition of an explicit line of sight reference
here, the SDT believes it has clarified its original intent.
Hopefully this will get us there. I’m sorry about the last-minute scramble, but I really appreciate all
the input!
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 6:43 PM
To: 'SDwyerIV@ameren.com'; Mallory Huggins
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
Agree that we want to go to recirc. So don't make changes that prohibit doing so
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 06:31 PM
To: Louis Slade (Services - 6); 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
Louis –
We did, so either is fine with me.
Mallory – you might want to try Louis' simpler words below first. If that doesn't fly, try the
switchyard wording if that's what we need to put this out for recirc.
Louis – Is that OK with you? I'd hate to see us lose our momentum at the last minute and I don't
think this is a deal-breaker – at least in my opinion.
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:01 PM
To: Dwyer IV, Samuel J; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
One thing troubles me. Didn't we have comments in this or past that stated some generating
facilities don have switch yards? If so, maybe just say clear line of sight between GSU and point of
interconnection
From: Louis Slade (Services - 6)
Sent: Tuesday, December 13, 2011 05:47 PM
To: 'SDwyerIV@ameren.com' ; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
information is prohibited and may be unlawful. If you have received this electronic
transmission in error, please reply immediately to the sender that you have received the
message in error, and delete it. Thank you.
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Attachments:
Dwyer IV, Samuel J
Mallory Huggins
scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:04:38 PM
20111213 SJD comment FAC-003-3_redline to last posted.doc
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Louis Slade
"SDwyerIV@ameren.com"; Mallory Huggins
"SHelyer@tnsk.com"
Re: FAC-003 Exception Language
Tuesday, December 13, 2011 6:01:28 PM
One thing troubles me. Didn't we have comments in this or past that stated some generating
facilities don have switch yards? If so, maybe just say clear line of sight between GSU and point of
interconnection
From: Louis Slade (Services - 6)
Sent: Tuesday, December 13, 2011 05:47 PM
To: 'SDwyerIV@ameren.com' ; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
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sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which
may be legally confidential and/or privileged and does not in any case represent a
firm ENERGY COMMODITY bid or offer relating thereto which binds the sender
without an additional express written confirmation to that effect. The information is
intended solely for the individual or entity named above and access by anyone else
is unauthorized. If you are not the intended recipient, any disclosure, copying,
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From:
To:
Cc:
Subject:
Date:
Dwyer IV, Samuel J
Mallory Huggins
scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
RE: FAC-003 Exception Language
Tuesday, December 13, 2011 5:44:17 PM
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended
recipient, or an employee or agent responsible for delivering this message to the
intended recipient, you are hereby notified that any dissemination, distribution or
copying of this communication is strictly prohibited. Note that any views or opinions
presented in this message are solely those of the author and do not necessarily
represent those of Ameren. All e-mails are subject to monitoring and archival.
Finally, the recipient should check this message and any attachments for the
presence of viruses. Ameren accepts no liability for any damage caused by any virus
transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any
computer. Ameren Corporation
From:
To:
Cc:
Subject:
Date:
Mallory Huggins
"Louis Slade"; "SDwyerIV@ameren.com"
"SHelyer@tnsk.com"
RE: FAC-003 Exception Language
Wednesday, December 14, 2011 9:21:00 AM
Louis, you were right that there were some folks concerned because their Facilities didn’t have
switchyards (and I raised that same concern when chatting with Laura about it), but I made a game
time decision and rationalized that (1) leaving the switchyard language in there ensures that we
change as little as possible between the last posting and now, and (2) we did get 85% support for
our changes, so I feel comfortable sticking with that language if we must. I wrapped up everything
last night and sent it on for posting, which will hopefully happen before noon. Here’s the
rationalization language I added both in a text box within the two FAC-003s, and in some of the
other docs:
With the line of sight reference in 4.3.1, the SDT simply seeks to clarify the exception
language based on the intent that has been agreed upon by the stakeholder body. In its
Consideration of Comments report from the last formal comment period, which ended on
July 17, 2011, the SDT explained “We believe that the one mile length is a reasonable
approximation of line of sight, and that using a fixed starting point (at the fenced area of
the generation station switchyard) eliminates confusion and any discretion on the part of a
Generator Owner or an auditor.” With the addition of an explicit line of sight reference
here, the SDT believes it has clarified its original intent.
Hopefully this will get us there. I’m sorry about the last-minute scramble, but I really appreciate all
the input!
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 6:43 PM
To: 'SDwyerIV@ameren.com'; Mallory Huggins
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
Agree that we want to go to recirc. So don't make changes that prohibit doing so
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 06:31 PM
To: Louis Slade (Services - 6); 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: RE: FAC-003 Exception Language
Louis –
We did, so either is fine with me.
Mallory – you might want to try Louis' simpler words below first. If that doesn't fly, try the
switchyard wording if that's what we need to put this out for recirc.
Louis – Is that OK with you? I'd hate to see us lose our momentum at the last minute and I don't
think this is a deal-breaker – at least in my opinion.
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Louis Slade [mailto:louis.slade@dom.com]
Sent: Tuesday, December 13, 2011 5:01 PM
To: Dwyer IV, Samuel J; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
One thing troubles me. Didn't we have comments in this or past that stated some generating
facilities don have switch yards? If so, maybe just say clear line of sight between GSU and point of
interconnection
From: Louis Slade (Services - 6)
Sent: Tuesday, December 13, 2011 05:47 PM
To: 'SDwyerIV@ameren.com' ; 'Mallory.Huggins@nerc.net'
Cc: 'SHelyer@tnsk.com'
Subject: Re: FAC-003 Exception Language
I think it looks pretty good. But is of 'or' correct? Should it be "and shorter lines that do not have a
clear line of sight......." ?
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 05:41 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com) ; Louis Slade (Services - 6)
Subject: RE: FAC-003 Exception Language
Mallory –
The whole premise from day one was use of the concept of "clear line of sight", so I don't see a
problem or any reason to think we've made any fundamental changes. If you look at the wording
changes on face value alone, you may conclude that, but we have not veered from our initial
concept. Hang tough because there's no reason to think we've made any change that should
prevent a recirc ballot. I know Louis is on vacation, but maybe Scott can confirm this.
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:33 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
I like that proposal…I was feeling similarly weird about the “origin of the line” thing. With your
change, it would look like this:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
switchyard fence to the point of interconnection and are:
All this discussion is making me a little bit nervous that stakeholders will see this is a bigger change
than we think it is, but I’ll do my best to write a really clear explanation. After our discussions in DC,
I couldn’t in good faith remove the line of sight reference altogether – I think it gets us a lot closer
to demonstrating the reliability-based need for the exception.
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:27 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I think you've got it. I have a thing for always trying to state the positive, rather than the negative,
but I agree the negative is what you want in this case. I would suggest one more change, instead of
"from the origin of the line" use "from the switchyard fence". It sounds a little repetitive, but I'm
concerned the phrase "origin of the line" is too vague. Is the "origin of the line" the generator
terminals inside the plant? The low-side of the GSU? The high-side of the GSU? The first tower
outside of the switchyard?
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 4:19 PM
To: Dwyer IV, Samuel J
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Sam, thanks so much for that. I think you might be going too far with the omission of transmission.
I agree that it’s a bit problematic, but with the disclaimer (“Within the text of NERC Reliability
Standard FAC-003-3, “transmission line(s) and “applicable line(s) can also refer to the generation
Facilities as referenced in 4.3 and its subsections.”), I think we can make it work.
I made some changes myself and was just trying to merge ours, but now I’m leaning back towards
my changes simply because they require no deletion, which might be more acceptable to
Maureen/Laura (looks less bloody, basically). Here’s what I was thinking:
Overhead transmission lines that extend greater than one mile (1.609 kilometers) beyond
the fenced area of the generating switchyard or do not have a clear line of sight from the
origin of the line to the point of interconnection and are:
Any thoughts? I’m going to give Laura a call and see if this is looking any better to her. If not, we
might need another plan…
From: Dwyer IV, Samuel J [mailto:SDwyerIV@ameren.com]
Sent: Tuesday, December 13, 2011 5:04 PM
To: Mallory Huggins
Cc: scott Helyer (shelyer@tnsk.com); Louis Slade (louis.slade@dom.com)
Subject: RE: FAC-003 Exception Language
Mallory –
I don't know for sure if this is what you want, but see red-lines in Section 4.3 to the attached file. I
may have gone too far, but that word "transmission" has been bothering me so your request gave
me the chance to remove it yet clearly identify the line with "generation". I'm sure someone else
can do better, but this is what I came up with…
Thanks,
Sam
Sam Dwyer : : Consulting Engineer, POS QMS : : T 314.957.3463
Ameren Missouri : : 3701 S Lindbergh Suite 204 : : St. Louis, MO 63127
From: Mallory Huggins [mailto:Mallory.Huggins@nerc.net]
Sent: Tuesday, December 13, 2011 2:38 PM
To: grti_sdt
Subject: FAC-003 Exception Language
Hi everyone,
There’s some concern that the exception language in FAC-003 may be perceived as changing the
scope of the previous changes, which would mean the standard couldn’t go to recirculation ballot
and would have to be posted for comment again. I think we have some solid background to justify
that it is just a clarifying change, because in a previous comment report we talked about line of
sight being the goal – and now we are simply clarifying that. I’m working on some language that
makes this clear for the comment report/technical justification document, but alongside that, we
need to see if we can format the language change we’ve proposed in the standard a way that’s a
little more concise.
I’ve attached what we have now. Any ideas? Ideally, we’d make this change this afternoon so we
can post for ballot tomorrow, but we also have the option of holding off until the first week of
January…
Thanks,
Mallory
--Mallory Huggins
Standards Specialist
North American Electric Reliability Corporation
1120 G Street NW, Suite 990, Washington, DC 20005
(p): 202-383-2639 | (c): 609-619-1629 | (f): 202-393-3955
--Y
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
The information contained in this message may be privileged and/or confidential and
protected from disclosure. If the reader of this message is not the intended recipient, or an
employee or agent responsible for delivering this message to the intended recipient, you are
hereby notified that any dissemination, distribution or copying of this communication is
strictly prohibited. Note that any views or opinions presented in this message are solely those
of the author and do not necessarily represent those of Ameren. All e-mails are subject to
monitoring and archival. Finally, the recipient should check this message and any
attachments for the presence of viruses. Ameren accepts no liability for any damage caused
by any virus transmitted by this e-mail. If you have received this in error, please notify the
sender immediately by replying to the message and deleting the material from any computer.
Ameren Corporation
CONFIDENTIALITY NOTICE: This electronic message contains information which may
be legally confidential and/or privileged and does not in any case represent a firm ENERGY
COMMODITY bid or offer relating thereto which binds the sender without an additional
express written confirmation to that effect. The information is intended solely for the
individual or entity named above and access by anyone else is unauthorized. If you are not
the intended recipient, any disclosure, copying, distribution, or use of the contents of this
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Ameren Corporation
Herb Schrayshuen
Vice President, Standards and Training
February 14, 2012
Via E-Mail
Mr. Steven T. Naumann
Vice President, Wholesale Market Development
Federal Regulatory Affairs & Public Policy
Exelon Corporation
Chase Tower-50th Floor
10 S. Dearborn Street
Chicago, Il 60603
Re: Exelon Level 1 Appeal of FAC-003x in Project 2010-07
Dear Steve,
In my role as Director of Standards you informed me, on January 13, 2012, of the possibility of filing an
appeal. On January 20, 2012 you filed, on the behalf of Exelon Corporation, a Level 1 Appeal of the
processing of FAC-003 in Project 2010-07 under the NERC standards development process and the
Rules of Procedure Section 300. In its appeal Exelon is contending that there was an improperly
implemented, substantive change to the standard (R4.3.1) regarding “line of site” between the last
successive and recirculation ballot.
Level 1 Appeals are managed within the current NERC Standard Processes Manual (SPM) dated
September 3, 2010 as follows:
•
Any entity that has directly and materially affected interests and that has been or will be adversely
affected by any procedural action or inaction related to the development, approval, revision,
reaffirmation, or withdrawal of a reliability standard, definition, variance, associated implementation
plan, or interpretation shall have the right to appeal. This appeals process applies only to the NERC
reliability standards processes as defined in this manual, not to the technical content of the standards
action.
The burden of proof to show adverse effect shall be on the appellant. Appeals shall be made within 30
days of the date of the action purported to cause the adverse effect, except appeals for inaction, which
may be made at any time.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
The final decisions of any appeal shall be documented in writing and made public.
The appeals process provides two levels, with the goal of expeditiously resolving the issue to the
satisfaction of the participants.
•
Level 1 Appeal
Level 1 is the required first step in the appeals process. The appellant shall submit (to the Director of
Standards) a complaint in writing that describes the procedural action or inaction associated with the
standards process. The appellant shall describe in the complaint the actual or potential adverse impact
to the appellant. Assisted by staff and industry resources as needed, the Director of Standards shall
prepare a written response addressed to the appellant as soon as practical but not more than 45 days
after receipt of the complaint. If the appellant accepts the response as a satisfactory resolution of the
issue, both the complaint and response shall be made a part of the public record associated with the
standard.
The FAC-003-x standard had been scheduled for Board of Trustees approval at its February 9, 2012
meeting, however, in order to permit the Level 1 Appeal process to properly run, it has been
withdrawn.
Information Requests
In response to the Level 1 Appeal, three information requests, each containing two questions, were
issued on January 25, 2012. One was issued to Exelon, one to NERC Standards Process Staff and one to
the Project 2010-07 Standards Drafting Team (SDT) Chair. The information requests and the responses
are appended to this letter which will be posted on the NERC website.
Findings
Timeliness of the Appeal:
The Standard Processes Manual calls for the filing of the appeal within 30 days of the date of the action
purported to cause the direct material adverse impact. The standard with the “line of site change” was
posted on December 14, 2011 and the ballot was finalized on December 23, 2011.
Within the project notice posted on December 14, 2011 it was clearly stated:
“In FAC-003-X and FAC-003-3, the SDT added a clarifying reference to line of sight in the GO
exemption in section 4.3.1. of both versions; corrected a typo in 4.3.1.2 of FAC-003-3; and changed
“RE” to “Regional Entity” in 4.3.1 of FAC-003-X.”
Page 2 of 4
In its response to the first information request Exelon notes its position that the adverse impact did not
occur until the ballot was concluded (unfavorably in Exelon’s view). On this basis Exelon believes its
January 13, 2012 preliminary notice of intent to file an appeal and the January 20, 2012 filing of the
appeal was timely under the SPM. I will consider the filing of this Level 1 Appeal as having been made
timely.
Adverse Impact:
Exelon notes in its response to Information Request 1 that it considers the direct material adverse
impact to be that it would be now subject as a Generator Owner/Generator Operator (GO/GOP) to the
proposed FAC-003-x standard given the line of sight clarification. It is a fair question as to whether
having a standard become applicable to a given entity is truly an adverse impact? If that were the case,
then every registered function would contend the same. I find that it is not an adverse impact for a
subset of Exelon’s nuclear facilities to become subject to the standard. Applicability by itself is not an
adverse impact. The interests of reliability must be served and if the SDT determines that a given set of
circumstances should result in a standard becoming applicable, then that is the technical design. On
the basis of applicability the appeal fails. The SDT in this project was charged specifically with the task
of determining which standards and requirements should be adjusted (and how they should be
adjusted) for applicability to GOs/GOPs.
Procedural Action:
Exelon believes that it did not have ample time to respond to the proposed change. Exelon contends it
was denied the ability to inform the industry. Exelon did provide some information of its efforts to
inform the industry of its beliefs, although apparently it was unpersuasive, given the outcome of the
ballot.
Material Change:
Based on the information request response from the SDT Chair, the SDT believes that the “line of sight”
change it made was clarifying and not material. I agree with Exelon, however that the line of sight
change also had the effect of changing the applicably of the standard based on its construct as Exelon
contends. This is within the technical scope for the SDT under the process. On this basis, I find that
Exelon has made its case that the SPM was not adhered to and that a change impacting applicability
was made between the last successive and recirculation ballot.
Page 3 of 4
Recommended Actions and Options
I refer the issue to the Standards Committee for handling. There are several options to consider:
1. Re-post the standard for a successive ballot and recirculation ballot. Essentially set the clock back and
correctly replay the last steps of the process.
2. Ask the SDT to remove the clarification language from the final standard and go directly to recirculation
ballot.
3. Ask the SDT to redesign the challenged portion of the proposed standard.
I recommend the Standards Committee pursue option 2.
Sincerely,
Herb Schrayshuen
Vice President, Standards and Training
cc: Mr. Gerry. Cauley, President and CEO, NERC
Mr. Ken Peterson, Chair, Board of Trustees Standards Oversight and Technology Committee
Mr. David Cook, General Counsel, NERC
Ms. Holly Hawkins, Associate General Counsel, NERC
Mr. Michael Moon, Director Compliance Operations, NERC
Ms. Laura Hussey, Manager Standards Process, NERC
Ms. Mallory Huggins, GO/TO Standards Drafting Team Advisor, NERC
Mr. Allen Mosher, Chair, Standards Committee
Mr. Louis Slade, Chair, GO/TO Standards Drafting Team
Attachments:
1) Appeal Letter dated January 20, 2012 from Exelon
2) Exelon Response to Data/Information Request
3) Information Request 1 to NERC Standards Process Staff (plus response)
4) Information Request 1 to GO/TO Drafting Team Chair (plus response)
Page 4 of 4
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 12
Draft 4: April 23, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by the
NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume that FAC003-2 will be approved by FERC and other governmental authorities. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, FAC-003-1, the current
FERC-approved version of the standard, and one to FAC-003-2, the version developed by the Project
2007-07 team and adopted by NERC’s Board of Trustees.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission Rights-of-Way
also refer to the generation Facilities
(ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity and the North American Electric Reliability Corporation
(NERC).
Applicability:
4.1. Regional Entity
4.2. Applicable Transmission Owner
4.2.1. Transmission Owner that owns overhead transmission lines operated at 200
kV and above and to any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an applicable qualified Facility, where a qualified
Facility is an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner’s
Facility or (2) does not have a clear line of sight 1 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric
system in the region.
4.4. Applicable Facilities
4.4.1. Transmission lines owned by a Transmission Owner that are operated at
200kV and above and any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
4.4.2. Qualified Facilities owned by applicable Generator Owners.
1
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
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Standard FAC-003-X — Transmission Vegetation Management Program
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions
where no regulatory approval is required, all requirements applied to the Transmission
Owner become effective upon Board of Trustees’ adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter
one year after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of
Trustees’ adoption, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirements R2, R3, and
R4 become effective on the first day of the first calendar quarter two years following
Board of Trustees’ adoption, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare and keep
current a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 2.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner in the TVMP
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 4: April 23, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
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Draft 4: April 23, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration
of the outage; a description of the cause of the outage; other pertinent comments; and
any countermeasures taken by the applicable Transmission Owner or applicable
Generator Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
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Draft 4: April 23, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
[VRF – Lower]
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance enforcement authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the Compliance Enforcement Authority.
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audit
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Draft 4: April 23, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below, unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
•
1.4.
The applicable Transmission Owner and applicable Generator Owner shall
retain evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
7 of 12
Draft 4: April 23, 2012
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
Standard FAC-003-X — Transmission Vegetation Management Program
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
8 of 12
Draft 4: April 23, 2012
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Standard FAC-003-X — Transmission Vegetation Management Program
OR
R1.2.2
R1.2.2.1
R1.2.2.2
R1.3
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
For responsible
entities directly
For responsible
entities directly
For responsible
entities directly
9 of 12
Draft 4: April 23, 2012
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
entities directly
Standard FAC-003-X — Transmission Vegetation Management Program
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
R1.4
R1.5
R2
N/A
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, three
of those persons
did not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 10% up to
(and including)
15%of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
N/A
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
The responsible
entity did not meet
two of the three
required elements
The responsible
entity did not meet
the three required
elements
10 of 12
Draft 4: April 23, 2012
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, more
than three of those
persons did not
hold appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 15% of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
Standard FAC-003-X — Transmission Vegetation Management Program
R3
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
management.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
E.
N/A
The responsible
entity has not
implemented the
annual plan for
vegetation
management.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
OR
N/A
N/A
N/A
Regional Differences
None Identified.
Version History
Version
Date
Action
11 of 12
Draft 4: April 23, 2012
Change Tracking
Standard FAC-003-X — Transmission Vegetation Management Program
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
April 23, 2012
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date; added
VSLs approved by FERC
12 of 12
Draft 4: April 23, 2012
Revision under Project
2010-07
Standard FAC-003-X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
Right-of-Way (ROW)
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
1 of 12
Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by the
NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume that FAC003-2 will be approved by FERC and other governmental authorities. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, FAC-003-1, the current
FERC-approved version of the standard, and one to FAC-003-2, the version developed by the Project
2007-07 team and adopted by NERC’s Board of Trustees.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rightsRights-of-way
also refer to the generation Facilities
Way (ROW) and minimizing outages from vegetation
as referenced in 4.4 and its
located adjacent to ROW, maintaining clearances
subsections.
between transmission lines and vegetation on and along
transmission ROW, and reporting vegetation-related outages of the transmission systems to
the respective Regional Entity (RE) and the North American Electric Reliability Council
Corporation (NERC).
Applicability:
4.1. Regional Entity
4.1.4.2.
Applicable Transmission Owner
4.1.1.4.2.1. Transmission Owner that owns overhead transmission lines operated at
200 kV and above and to any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
4.2.4.3.
Applicable Generator Owner
4.3.1. Generator Owner that owns an applicable qualified Facility, where a qualified
Facility is an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner’s
Facility or (2) does not have a clear line of sight 1 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric
system in the region.
4.4. Applicable Facilities
4.4.1. Transmission lines owned by a Transmission Owner that are operated at
200kV and above and any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
4.2.1.4.4.2. Qualified Facilities owned by applicable Generator Owners.
1
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
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Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
5.
Effective Dates:
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions where no
regulatory approval is required, all requirements applied to the Transmission Owner become
effective upon Board of Trustees’ adoption or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one year
after the date of the order approving the standard from applicable regulatory authorities where
such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the
first calendar quarter one year following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first calendar
quarter two years after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those jurisdictions
where no regulatory approval is required, Requirements R2, R3, and R4 become effective on
the first day of the first calendar quarter two years following Board of Trustees’ adoption or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B.
Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 2.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. Each applicable Transmission Owner or applicable Generator Owner, in the TVMP,
shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
3 of 12
Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
[VRF – High]
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Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its Regional Entity, or the Regional Entity’s designee, sustained transmission line outages
determined by the applicable Transmission Owner or applicable Generator Owner to have
been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the Regional Entity, or the Regional Entity’s designee, certain sustained
transmission line outages caused by vegetation: (1) Vegetation-related outages that
result from vegetation falling into lines from outside the ROW that result from natural
disasters shall not be considered reportable (examples of disasters that could create
non-reportable outages include, but are not limited to, earthquakes, fires, tornados,
hurricanes, landslides, wind shear, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body,
ice storms, and floods), and (2) Vegetation-related outages due to human or animal
activity shall not be considered reportable (examples of human or animal activity that
could cause a non-reportable outage include, but are not limited to, logging, animal
severing tree, vehicle contact with tree, arboricultural activities or horticultural or
agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the Regional Entity, or the Regional Entity’s designee, shall
include at a minimum: the name of the circuit(s) outaged, the date, time and duration of
the outage; a description of the cause of the outage; other pertinent comments; and any
countermeasures taken by the applicable Transmission Owner or applicable Generator
Owner.
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
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Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R4. The Regional Entity shall report the outage information provided to it by applicable
Transmission Owners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of
the reported outages.
[VRF – Lower]
C.
Measures
M1. Each applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. Each applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. Each applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. Each applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. Each applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. Each applicable Transmission Owner or applicable Generator Owner has documentation that
the Transmission Owner implemented the work plan identified in Requirement 2.
M3. Each applicable Transmission Owner or applicable Generator Owner has documentation that it
has supplied quarterly outage reports to the Regional Entity, or the Regional Entity’s designee,
as identified in Requirement 3.
M4. The Regional Entity has documentation that it provided quarterly outage reports to NERC as
identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance enforcement authority unless
the applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the Compliance Enforcement Authority.
Compliance Monitor:
• Regional Entity for the Transmission Owner and Generator Owner
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Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
• Electric Reliability Organization or another Regional Entity approved by the
ERO and FERC or other applicable government authorities
1.2.
Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3.
Data Retention
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
• The applicable Transmission Owner and applicable Generator Owner shall retain
evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
1.4.
Additional Compliance Information
None.
2.
Violation Severity Levels
R#
R1
R1.1
R1.2
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
by the
requirement.
N/A
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
requirement.
N/A
N/A
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
7 of 12
Draft 34: March 6April 123, 2012
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
Standard FAC-003-X — Transmission Vegetation Management Program
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
R1.2.1
N/A
N/A
8 of 12
Draft 34: March 6April 123, 2012
N/A
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
Standard FAC-003-X — Transmission Vegetation Management Program
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
R1.2.2
R1.2.2.1
R1.2.2.2
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
9 of 12
Draft 34: March 6April 123, 2012
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phase-
Standard FAC-003-X — Transmission Vegetation Management Program
R1.3
R1.4
R1.5
to-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
For responsible
For responsible
For responsible
entities directly
entities directly
entities directly
entities directly
involving fewer
involving fewer
involving fewer
involving fewer
than 20 persons in than 20 persons in than 20 persons in than 20 persons in
the design and
the design and
the design and
the design and
implementation of implementation of implementation of implementation of
the TVMP, one of the TVMP, two of the TVMP, three
the TVMP, more
those persons did
those persons did
of those persons
than three of those
not hold
not hold
did not hold
persons did not
appropriate
appropriate
appropriate
hold appropriate
qualifications and
qualifications and
qualifications and
qualifications and
training to perform training to perform training to perform training to perform
their duties. For
their duties. For
their duties. For
their duties. For
responsible entities responsible entities responsible entities responsible entities
directly involving
directly involving
directly involving
directly involving
20 or more persons 20 or more persons 20 or more persons 20 or more persons
in the design and
in the design and
in the design and
in the design and
implementation of implementation of implementation of implementation of
the TVMP, 5% or
the TVMP, more
the TVMP, more
the TVMP, more
less of those
than 5% up to (and than 10% up to
than 15% of those
persons did not
including) 10%of
(and including)
persons did not
hold appropriate
those persons did
15%of those
hold appropriate
qualifications and
not hold
persons did not
qualifications and
training to perform appropriate
hold appropriate
training to perform
their duties.
qualifications and
qualifications and
their duties.
training to perform training to perform
their duties.
their duties.
N/A
N/A
N/A
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
clearances where
restrictions to the
ROW are in effect.
N/A
N/A
N/A
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
10 of 12
Draft 34: March 6April 123, 2012
Standard FAC-003-X — Transmission Vegetation Management Program
R2
R3
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
OR
E.
N/A
N/A
Regional Differences
11 of 12
Draft 34: March 6April 123, 2012
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
management.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
The responsible
entity provided a
quarterly report,
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
N/A
N/A
Standard FAC-003-X — Transmission Vegetation Management Program
None Identified.
Version History
Version
Date
Action
Change Tracking
1
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
May 16,
2011April 23,
2012
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date; added
VSLs approved by FERC
12 of 12
Draft 34: March 6April 123, 2012
Revision under Project
2010-07
Standard FAC-003-1X — Transmission Vegetation Management Program
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
When this standard has received ballot approval, the text boxes will be moved to the Guideline and
Technical Basis Section.
Right-of-Way (ROW)
The current glossary definition
of this NERC term was
modified to include applicable
Generator Owners.
A corridor of land on which electric lines may be located. The
applicable Transmission Owner or applicable Generator Owner
may own the land in fee, own an easement, or have certain
franchise, prescription, or license rights to construct and maintain lines.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by the
NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume that FAC003-2 will be approved by FERC and other governmental authorities. Thus, the Project 2010-07
drafting team has developed two sets of proposed changes: one to this version, FAC-003-1, the current
FERC-approved version of the standard, and one to FAC-003-2, the version developed by the Project
2007-07 team and adopted by NERC’s Board of Trustees.
A.
Introduction
1.
Title:
Transmission Vegetation Management Program
2.
Number:
FAC-003-1X
3.
4.
Within the text of NERC Reliability
Purpose: To improve the reliability of the electric
Standard FAC-003-X, “transmission
transmission systems by preventing outages from
line(s)” and “applicable line(s)” can
vegetation located on transmission rightsRights-ofalso refer to the generation Facilities
wayWay (ROW) and minimizing outages from
as referenced in 4.4 and its
vegetation located adjacent to ROW, maintaining
subsections.
clearances between transmission lines and vegetation
on and along transmission ROW, and reporting vegetation-related outages of the transmission
systems to the respective Regional Reliability Organizations (RRO)Entity and the North
American Electric Reliability CouncilCorporation (NERC).
Applicability:
4.1. Regional Entity
4.1.4.2.
Applicable Transmission Owner.
4.2.Regional Reliability Organization.
4.2.1. This standard shall apply to allTransmission Owner that owns overhead
transmission lines operated at 200 kV and above and to any lower voltage
lines designated by the RRORegional Entity as critical to the reliability of the
electric system in the region.
4.3. Applicable Generator Owner
4.3.1. Generator Owner that owns an applicable qualified Facility, where a qualified
Facility is an overhead transmission line(s) that (1) extends greater than one
mile or 1.609 kilometers beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner’s
Facility or (2) does not have a clear line of sight 1 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and is operated at 200 kV and above and any lower voltage lines
designated by the Regional Entity as critical to the reliability of the electric
system in the region.
4.4. Applicable Facilities
4.4.1. Transmission lines owned by a Transmission Owner that are operated at
200kV and above and any lower voltage lines designated by the Regional
Entity as critical to the reliability of the electric system in the region.
1
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
4.4.2.
5.
Qualified Facilities owned by applicable Generator Owners.
Effective Dates:
5.1.One calendar year from the date of adoption by the NERC Board of Trustees for
Requirements 1 and 2.
5.2.Sixty calendar days from the date of adoption by the NERC Board of Trustees for
Requirements 3 and 4.
B.Requirements
The Transmission There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements applied to the
Transmission Owner become effective upon regulatory approval. In those jurisdictions
where no regulatory approval is required, all requirements applied to the Transmission
Owner become effective upon Board of Trustees’ adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
In those jurisdictions where regulatory approval is required, Requirement R1 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter
one year after the date of the order approving the standard from applicable regulatory
authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of
Trustees’ adoption, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
The third effective date allows entities time to comply with Requirements R2, R3, and R4.
In those jurisdictions where regulatory approval is required, Requirements R2, R3, and R4
applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirements R2, R3, and
R4 become effective on the first day of the first calendar quarter two years following
Board of Trustees’ adoption, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
C.B. Requirements
R1. Each applicable Transmission Owner or applicable Generator Owner shall prepare, and keep
current, a formal transmission vegetation management program (TVMP). The TVMP shall
include the applicable Transmission Owner’s or applicable Generator Owner’s objectives,
practices, approved procedures, and work specifications 2.
R1.1. The TVMP shall define a schedule for and the type (aerial, ground) of ROW vegetation
inspections. This schedule should be flexible enough to adjust for changing
conditions. The inspection schedule shall be based on the anticipated growth of
2
ANSI A300, Tree Care Operations – Tree, Shrub, and Other Woody Plant Maintenance – Standard Practices, while
not a requirement of this standard, is considered to be an industry best practice.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
vegetation and any other environmental or operational factors that could impact the
relationship of vegetation to the applicable Transmission Owner’s or applicable
Generator Owner’s transmission lines.
R1.2. TheEach applicable Transmission Owner, or applicable Generator Owner in the
TVMP, shall identify and document clearances between vegetation and any overhead,
ungrounded supply conductors, taking into consideration transmission line voltage, the
effects of ambient temperature on conductor sag under maximum design loading, and
the effects of wind velocities on conductor sway. Specifically, the applicable
Transmission Owner or applicable Generator Owner shall establish clearances to be
achieved at the time of vegetation management work identified herein as Clearance 1,
and shall also establish and maintain a set of clearances identified herein as Clearance
2 to prevent flashover between vegetation and overhead ungrounded supply
conductors.
R1.2.1. Clearance 1 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document appropriate clearance distances to be
achieved at the time of transmission vegetation management work based upon
local conditions and the expected time frame in which the applicable
Transmission Owner or applicable Generator Owner plans to return for future
vegetation management work. Local conditions may include, but are not
limited to: operating voltage, appropriate vegetation management techniques,
fire risk, reasonably anticipated tree and conductor movement, species types
and growth rates, species failure characteristics, local climate and rainfall
patterns, line terrain and elevation, location of the vegetation within the span,
and worker approach distance requirements. Clearance 1 distances shall be
greater than those defined by Clearance 2 below.
R1.2.2. Clearance 2 — The applicable Transmission Owner or applicable Generator
Owner shall determine and document specific radial clearances to be
maintained between vegetation and conductors under all rated electrical
operating conditions. These minimum clearance distances are necessary to
prevent flashover between vegetation and conductors and will vary due to
such factors as altitude and operating voltage. These applicable Transmission
Owner-specific or applicable Generator Owner-specific minimum clearance
distances shall be no less than those set forth in the Institute of Electrical and
Electronics Engineers (IEEE) Standard 516-2003 (Guide for Maintenance
Methods on Energized Power Lines) and as specified in its Section 4.2.2.3,
Minimum Air Insulation Distances without Tools in the Air Gap.
R1.2.2.1 Where transmission system transient overvoltage factors are not
known, clearances shall be derived from Table 5, IEEE 516-2003,
phase-to-ground distances, with appropriate altitude correction
factors applied.
R1.2.2.2 Where transmission system transient overvoltage factors are
known, clearances shall be derived from Table 7, IEEE 516-2003,
phase-to-phase voltages, with appropriate altitude correction
factors applied.
R1.3. All personnel directly involved in the design and implementation of the TVMP shall
hold appropriate qualifications and training, as defined by the Transmission Owner or
Generator Owner, to perform their duties.
R1.4. Each applicable Transmission Owner or applicable Generator Owner shall develop
mitigation measures to achieve sufficient clearances for the protection of the
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
transmission facilities when it identifies locations on the ROW where the Transmission
Owner or applicable Generator Owner is restricted from attaining the clearances
specified in Requirement 1.2.1.
R1.5. Each Transmission Owner or applicable Generator Owner shall establish and
document a process for the immediate communication of vegetation conditions that
present an imminent threat of a transmission line outage. This is so that action
(temporary reduction in line rating, switching line out of service, etc.) may be taken
until the threat is relieved.
The[VRF – High]
R2. Each applicable Transmission Owner or applicable Generator Owner shall create and
implement an annual plan for vegetation management work to ensure the reliability of the
system. The plan shall describe the methods used, such as manual clearing, mechanical
clearing, herbicide treatment, or other actions. The plan should be flexible enough to adjust to
changing conditions, taking into consideration anticipated growth of vegetation and all other
environmental factors that may have an impact on the reliability of the transmission systems.
Adjustments to the plan shall be documented as they occur. The plan should take into
consideration the time required to obtain permissions or permits from landowners or
regulatory authorities. Each applicable Transmission Owner or applicable Generator Owner
shall have systems and procedures for documenting and tracking the planned vegetation
management work and ensuring that the vegetation management work was completed
according to work specifications.
The[VRF – High]
R3. Each applicable Transmission Owner or applicable Generator Owner shall report quarterly to
its RRORegional Entity, or the RRO’sRegional Entity’s designee, sustained transmission line
outages determined by the applicable Transmission Owner or applicable Generator Owner to
have been caused by vegetation.
R3.1. Multiple sustained outages on an individual line, if caused by the same vegetation,
shall be reported as one outage regardless of the actual number of outages within a 24hour period.
R3.2. The applicable Transmission Owner or applicable Generator Owner is not required to
report to the RRORegional Entity, or the RRO’sRegional Entity’s designee, certain
sustained transmission line outages caused by vegetation: (1) Vegetation-related
outages that result from vegetation falling into lines from outside the ROW that result
from natural disasters shall not be considered reportable (examples of disasters that
could create non-reportable outages include, but are not limited to, earthquakes, fires,
tornados, hurricanes, landslides, wind shear, major storms as defined either by the
applicable Transmission Owner or applicable Generator Owner or an applicable
regulatory body, ice storms, and floods), and (2) Vegetation-related outages due to
human or animal activity shall not be considered reportable (examples of human or
animal activity that could cause a non-reportable outage include, but are not limited to,
logging, animal severing tree, vehicle contact with tree, arboricultural activities or
horticultural or agricultural activities, or removal or digging of vegetation).
R3.3. The outage information provided by the applicable Transmission Owner or applicable
Generator Owner to the RRORegional Entity, or the RRO’sRegional Entity’s designee,
shall include at a minimum: the name of the circuit(s) outaged, the date, time and
duration of the outage; a description of the cause of the outage; other pertinent
comments; and any countermeasures taken by the applicable Transmission Owner or
applicable Generator Owner.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
R3.4. An outage shall be categorized as one of the following:
R3.4.1. Category 1 — Grow-ins: Outages caused by vegetation growing into lines
from vegetation inside and/or outside of the ROW;
R3.4.2. Category 2 — Fall-ins: Outages caused by vegetation falling into lines from
inside the ROW;
R3.4.3. Category 3 — Fall-ins: Outages caused by vegetation falling into lines from
outside the ROW.
[VRF – Lower]
R4. The RRORegional Entity shall report the outage information provided to it by applicable
Transmission Owner’sOwners or applicable Generator Owners, as required by Requirement 3,
quarterly to NERC, as well as any actions taken by the RRORegional Entity as a result of any
of the reported outages.
[VRF – Lower]
C.
Measures
M1. TheEach applicable Transmission Owner or applicable Generator Owner has a documented
TVMP, as identified in Requirement 1.
M1.1. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that the applicable Transmission Owner or applicable Generator Owner
performed the vegetation inspections as identified in Requirement 1.1.
M1.2. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that describes the clearances identified in Requirement 1.2.
M1.3. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that the personnel directly involved in the design and implementation
of the applicable Transmission Owner’s or applicable Generator Owner TVMP hold
the qualifications identified by the Transmission Owner or applicable Generator Owner
as required in Requirement 1.3.
M1.4. TheEach applicable Transmission Owner or applicable Generator Owner has
documentation that it has identified any areas not meeting the applicable Transmission
Owner’s or applicable Generator Owner’s standard for vegetation management and
any mitigating measures the Transmission Owner or applicable Generator Owner has
taken to address these deficiencies as identified in Requirement 1.4.
M1.5. TheEach applicable Transmission Owner or applicable Generator Owner has a
documented process for the immediate communication of imminent threats by
vegetation as identified in Requirement 1.5.
M2. TheEach applicable Transmission Owner or applicable Generator Owner has documentation
that the Transmission Owner implemented the work plan identified in Requirement 2.
M3. The Each applicable Transmission Owner or applicable Generator Owner has documentation
that it has supplied quarterly outage reports to the RRORegional Entity, or the RRO’sRegional
Entity’s designee, as identified in Requirement 3.
M4. The RRORegional Entity has documentation that it provided quarterly outage reports to
NERC as identified in Requirement 4.
D.
Compliance
1.
Compliance Monitoring Process
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
1.1.
Compliance Monitoring ResponsibilityEnforcement Authority
RRO
NERC
The Regional Entity shall serve as the Compliance enforcement authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the Compliance Enforcement Authority.
1.2.
Compliance Monitoring Period and ResetEnforcement Processes:
One calendar Year
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3.
Data Retention
Five Years
The applicable Transmission Owner and applicable Generator Owner shall keep data
or evidence to show compliance as identified below, unless directed by its Compliance
Enforcement Authority to retain specific evidence for a longer period of time as part of
an investigation:
•
1.4.
The applicable Transmission Owner and applicable Generator Owner shall
retain evidence of Requirement 1, Measure 1, Requirement 2, Measure 2, and
Requirement 3, Measure 3 from its last audit.
Additional Compliance Information
The VSLs shown below were approved by
The Transmission Owner shall demonstrate compliance through self-certification
FERC after FAC-003-1 was approved –
submitted to the compliance monitor (RRO) annually that it meets the requirements of
only the changes associated with
NERC Reliability Standard FAC-003-1. The compliance monitor shall conduct an ondeveloping FAC-003-X are shown in
site audit every five years or more frequently as deemed appropriate by the compliance
monitor to review documentation related to Reliability Standard FAC-003-1. Field
audits of ROW vegetation conditions may be conducted if determined to be necessary
by the compliance monitor.
None.
2.
Violation Severity Levels
R#
R1
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible
entity did not
include and keep
current one of the
four required
elements of its
TVMP, as directed
The responsible
entity did not
include and keep
current two of the
four required
elements of its
TVMP, as directed
The responsible
entity did not
include and keep
current three of the
four required
elements of its
TVMP, as directed
The responsible
entity did not
include and keep
current all required
elements of the
TVMP, as directed
by the
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
R1.1
R1.2
by the
requirement.
N/A
by the
requirement.
N/A
N/A
N/A
by the
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, or the
type of ROW
vegetation
inspections, as
directed by the
requirement.
N/A
requirement.
The applicable
entity TVMP did
not define a
schedule, as
directed by the
requirement, nor
the type of ROW
vegetation
inspections, as
directed by the
requirement.
The responsible
entity, in its
TVMP, failed to
identify and
document
clearances
between
vegetation and any
overhead,
ungrounded supply
conductors.
OR
The responsible
entity, in its
TVMP, failed to
take into
consideration
transmission line
voltage, or the
effects of ambient
temperature on
conductor sag
under maximum
design loading, or
the effects of wind
velocities on
conductor sway.
OR
The responsible
entity, in its
TVMP, failed to
establish
Clearance 1 or
Clearance 2
values.
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
R1.2.1
N/A
N/A
N/A
The responsible
entity failed to
determine and
document an
appropriate
clearance distance
to be achieved at
the time of
transmission
vegetation
management work
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
OR
R1.2.2
R1.2.2.1
N/A
N/A
N/A
N/A
N/A
N/A
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
The responsible
entity documented
a Clearance 1
value that was
smaller than its
Clearance 2 value.
The responsible
entity failed to
determine and
document
Clearance 2 values
taking into account
local conditions
and the expected
time frame in
which the
responsible entity
expects to return
for future
vegetation
management work.
Where
transmission
system transient
overvoltage factors
were known,
clearances were
not derived from
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Standard FAC-003-1X — Transmission Vegetation Management Program
R1.2.2.2
R1.3
R1.4
N/A
N/A
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, one of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, 5% or
less of those
persons did not
hold appropriate
qualifications and
training to perform
their duties.
For responsible
entities directly
involving fewer
than 20 persons in
the design and
implementation of
the TVMP, two of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties. For
responsible entities
directly involving
20 or more persons
in the design and
implementation of
the TVMP, more
than 5% up to (and
including) 10%of
those persons did
not hold
appropriate
qualifications and
training to perform
their duties.
N/A
N/A
Table 5, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
N/A
Where
transmission
system transient
overvoltage factors
are known,
clearances were
not derived from
Table 7, IEEE
516-2003, phaseto-phase voltages,
with appropriate
altitude correction
factors applied.
For responsible
For responsible
entities directly
entities directly
involving fewer
involving fewer
than 20 persons in than 20 persons in
the design and
the design and
implementation of implementation of
the TVMP, three
the TVMP, more
of those persons
than three of those
did not hold
persons did not
appropriate
hold appropriate
qualifications and
qualifications and
training to perform training to perform
their duties. For
their duties. For
responsible entities responsible entities
directly involving
directly involving
20 or more persons 20 or more persons
in the design and
in the design and
implementation of implementation of
the TVMP, more
the TVMP, more
than 10% up to
than 15% of those
(and including)
persons did not
15%of those
hold appropriate
persons did not
qualifications and
hold appropriate
training to perform
qualifications and
their duties.
training to perform
their duties.
N/A
The responsible
entity's TVMP
does not include
mitigation
measures to
achieve sufficient
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Standard FAC-003-1X — Transmission Vegetation Management Program
R1.5
R2
R3
N/A
N/A
N/A
The responsible
entity did not meet
one of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
two of the three
required elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity did not meet
the three required
elements
(including in the
annual plan a
description of
methods used for
vegetation
management,
maintaining
documentation of
adjustments to the
annual plan, or
having systems
and procedures for
tracking work
performed as part
of the annual plan)
specified in the
requirement.
The responsible
entity failed to
provide a quarterly
outage report, but
did not experience
any reportable
outages.
The responsible
entity provided a
quarterly report,
but failed to
include
information
required by R3.3.
The responsible
entity provided a
quarterly outage
report, but failed
to include a
reportable
Category 3 outage
as described in
R3.4.3.
OR
The responsible
entity provided a
quarterly report,
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
clearances where
restrictions to the
ROW are in effect.
The responsible
entity did not
establish or did not
document a
process for the
immediate
communication of
vegetation
conditions that
present an
imminent threat of
line outage, as
directed by the
requirement.
The responsible
entity does not
have an annual
plan for vegetation
management.
OR
The responsible
entity has not
implemented the
annual plan for
vegetation
management.
The responsible
entity experienced
reportable outages
but failed to
provide a quarterly
report.
OR
The responsible
entity provided a
quarterly outage
report, but failed
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Standard FAC-003-1X — Transmission Vegetation Management Program
but failed to report
in the manner
specified by one or
more of the
following
subcomponents of
Requirement R3:
R3.1 or R3.2.
R4
E.
Not applicable.N/A
to include a
reportable
Category 1 (as
described in
R3.4.1) or
Category 2 outage
(as described in
R3.4.2).
Not applicable.N/A
N/AThe RRO did
not submit a
quarterly report to
NERC for a single
quarter.
N/AThe RRO did
not submit a
quarterly report to
NERC for more than
two consecutive
quarters.
Regional Differences
None Identified.
Version History
Version
Version 1
Date
Action
Change Tracking
TBA
1. Added “Standard Development
Roadmap.”
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date: April
7, 2006” to footer.
4. Added “Draft 3: November 17, 2005” to
footer.
X
April 23, 2012
Made standard applicable to certain
qualifying Generator Owners and brought
overall standard format up to date; added
VSLs approved by FERC
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
Revision under Project
2010-07
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Standard FAC-003-1X — Transmission Vegetation Management Program
Adopted by NERC Board of Trustees: February 7, 2006
Effective DateDraft 4: April 7, 200623, 2012
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Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired at midnight the day before FAC-003-X becomes effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4and add applicable Generator Owner to
certain requirements). Therefore, this implementation plan only identifies a compliance
timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
April 24, 2012
1
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMPs and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption or as
otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
April 24, 2012
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees’ adoption or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
April 24, 2012
3
Implementation Plan for FAC-003-X – Transmission Vegetation Management
Program
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in
progress or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards.
FAC-003-1 will be retired at midnight the day before FAC-003-X becomes effective.
There is one revised definition in the proposed standard:
Right-of-Way: A corridor of land on which electric lines may be located. The
Transmission Owner or applicable Generator Owner may own the land in fee,
own an easement, or have certain franchise, prescription, or license rights to
construct and maintain lines.
The current glossary definition of Right-of-Way will be retired at midnight the day before
FAC-003-X (and with it, the above definition of Right-of-Way) becomes effective.
Compliance with Standard
There are no changes to the requirements applicable to Transmission Owners already in
effect in FAC-003-1, and the expectation is that Transmission Owners will maintain their
current state of compliance. Thus, the standard is effective for Transmission Owners
upon approval, as detailed below.
The proposed changes to FAC-003-1 only address Generator Owner applicability and
requirements (add Generator Owner to section 4.3 and add applicable Generator Owner
to all certain requirements). Therefore, this implementation plan only identifies a
compliance timeframe for Generator Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full
review of as-built drawings and determine which generation interconnection Facilities
require a Transmission Vegetation Management Plan (TVMP) and inspection as specified
by NERC Reliability Standard FAC-003-X. In general, Generator Owners do not have
staff that are qualified and experienced to create a TVMP and implement annual plans for
vegetation management. Once a complete inventory is created, the Generator Owner will
begin the process of gathering information for the TVMP. In instances where the
generation interconnection Facilities are owned by a partnership, a majority or operating
partner will need to obtain partnership approval to proceed with procurement of a TVMP
expert, and later a tree trimming crew. Typically, a request for proposal to hire TVMP
consultant is initiated, which could take several weeks in order to obtain sufficient bids
(and also satisfy Sarbanes Oxley requirements). Once all bids have been received, a
contract with a TVMP consultant is signed. At this point, the TVMP consultant and
April 24, 2012
1
Generator Owner staff will develop the TVMP, which needs to take into account local
growth conditions, types of vegetation and other aspects required by FAC-003-X. Once
the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection, usually done using GPS, LIDAR and other tools by
experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator
Owner will need to issue a request for proposal to hire a tree trimming crew that is
qualified and experienced to perform required clearance trimming. Once all bids have
been received, a contract with a tree trimming crew is signed. When the tree trimming
crew is acquired, the crew will need to familiarize themselves with the entity's TVMP
and required clearances. The Generator Owner will typically need to schedule any
required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan. During
scheduled outages, if required, the tree trimming crew will perform any required
clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining
TVMP-related activities, including maintenance of inspection and clearance
documentation. On an ongoing basis, in addition to performing inspections and
clearances as required by the entity's TVMP, the Generator Owner will need to ensure
that the training and qualification requirements for the standard are met. The entity will
also need to maintain documentation of all FAC-003-X activities for compliance period
of one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-X,
compliance with this standard by a Generator Owner may take as long as two years – in
part because many entities will have generator interconnection Facilities in various parts
of the country which may require several instances of TVMPs and numerous Right-ofWay inspections.
Effective Date
There are three effective dates associated with this implementation plan:
The first effective date applies to Transmission Owners.
In those jurisdictions where regulatory approval is required, all requirements
applied to the Transmission Owner become effective upon approval. In those
jurisdictions where no regulatory approval is required, all requirements applied to
the Transmission Owner become effective upon Board of Trustees’ adoption or as
otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The second effective date allows Generator Owners time to prepare a formal transmission
vegetation management program as outlined in Requirement R1.
April 24, 2012
2
In those jurisdictions where regulatory approval is required, Requirement R1
applied to the Generator Owner becomes effective on the first calendar day of the
first calendar quarter one year after the date of the order approving the standard
from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is
required, Requirement R3 R1 becomes effective on the first day of the first calendar
quarter one year following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The third effective date allows entities time to comply with Requirements R2, R3, and
R4.
In those jurisdictions where regulatory approval is required, Requirements R2,
R3, and R4 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for
all requirements is required. In those jurisdictions where no regulatory approval is
required, Requirements R2, R3, and R4 become effective on the first day of the first
calendar quarter two years following Board of Trustees’ adoption or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
April 24, 2012
3
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees’
adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 4: April 23, 2012
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 4: April 23, 2012
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
2
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
The Project 2010-07 team further modified that
construction documents, pre-2007 vegetation
proposed definition to include applicable
maintenance records, or by the blowout standard in
Generator Owners.
effect when the line was built. The ROW width in
no case exceeds the applicable Transmission Owner’s or applicable Generator Owner’s legal
rights but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
The Project 2010-07 team further modified that
proposed definition to include applicable
Generator Owners.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance
(MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 4: April 23, 2012
3
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by
the NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume
that FAC-003-2 will be approved by FERC and other governmental authorities. Thus, the
Project 2010-07 drafting team has developed two sets of proposed changes: one to this version,
FAC-003-2, the version developed by the Project 2007-07 team and adopted by NERC’s Board
of Trustees, and one to FAC-003-1, the current FERC-approved version of the standard.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1 Transmission Owners that own Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own
generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands
owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2. 1 Each overhead transmission line operated
at 200kV or higher.
1
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 4: April 23, 2012
4
FAC-003-3 — Transmission Vegetation Management
4.2.2 Each overhead transmission line operated below 200kV identified as an element
of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3 Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4 Each overhead transmission line identified above (4.2.1 through 4.2.3) located
outside the fenced area of the switchyard, station or substation and any portion of the
span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1 Overhead transmission lines that (1) extend
Standard FAC-003-3, “transmission
line(s) and “applicable line(s) can
greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station
also refer to the generation Facilities
as referenced in 4.3 and its
switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a
subsections.
clear line of sight 3 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Draft 4: April 23, 2012
5
FAC-003-3 — Transmission Vegetation Management
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
Draft 4: April 23, 2012
6
FAC-003-3 — Transmission Vegetation Management
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
Performance-based: Requirements 1 and 2
Competency-based: Requirement 3
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
Draft 4: April 23, 2012
7
FAC-003-3 — Transmission Vegetation Management
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Draft 4: April 23, 2012
8
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 4 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 5,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 6,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
4
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 4: April 23, 2012
9
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Draft 4: April 23, 2012
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FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
vegetation growth rates, vegetation control methods, and
inspection frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Draft 4: April 23, 2012
11
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or
Rationale
evidence that the line was de-energized.
Inspections are used by applicable
(R5)
Transmission Owners and applicable
Generator Owners to assess the condition of
the entire ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
R6. Each applicable Transmission Owner and
recently-completed work. This requirement
applicable Generator Owner shall perform
sets a minimum Vegetation Inspection
a Vegetation Inspection of 100% of its
frequency of once per calendar year but
applicable transmission lines (measured in
with no more than 18 months between
units of choice - circuit, pole line, line
inspections on the same ROW. Based upon
miles or kilometers, etc.) at least once per
average growth rates across North America
calendar year and with no more than 18
and on common utility practice, this
calendar months between inspections on
minimum frequency is reasonable.
the same ROW 7 [Violation Risk Factor:
Transmission Owners should consider local
and environmental factors that could
7
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 4: April 23, 2012
12
FAC-003-3 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 8
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
8
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 4: April 23, 2012
13
FAC-003-3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance enforcement authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcement Authority.
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Draft 4: April 23, 2012
14
FAC-003-3 — Transmission Vegetation Management
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
Draft 4: April 23, 2012
15
FAC-003-3 — Transmission Vegetation Management
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Draft 4: April 23, 2012
16
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 4: April 23, 2012
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
17
A grow-in
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
Long-Term
Planning
Real-time
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
Lower
Medium
R5
Operations
Planning
Medium
R6
Operations
Medium
Draft 4: April 23, 2012
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
The responsible entity
The responsible entity failed
The responsible entity failed to
18
The responsible entity failed to
FAC-003-3 — Transmission Vegetation Management
Planning
R7
Operations
Planning
Medium
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Draft 4: April 23, 2012
19
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by an applicable Transmission Owner or applicable Generator Owner from a third party
Draft 4: April 23, 2012
20
FAC-003-3 — Transmission Vegetation Management
such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission Owner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set
forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners may
in some cases own more property or rights than are needed to reliably operate transmission lines.
This modified definition represents a slight but significant departure from the strict legal definition
of “right of way” in that this definition is based on engineering and construction considerations
that establish the width of a corridor from a technical basis. The pre-2007 maintenance records are
included in the revised definition to allow the use of such vegetation widths if there were no
engineering or construction standards that referenced the width of right of way to be maintained
for vegetation on a particular line but the evidence exists in maintenance records for a width that
was in fact maintained prior to this standard becoming mandatory. Such widths may be the only
information available for lines that had limited or no vegetation easement rights and were typically
maintained primarily to ensure public safety. This standard does not require additional easement
rights to be purchased to satisfy a minimum right of way width that did not exist prior to this
standard becoming mandatory.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance
inspections and vegetation inspections to be performed concurrently. This allows potential
efficiencies, especially for those lines with minimal vegetation and/or slow vegetation growth
rates.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Draft 4: April 23, 2012
21
FAC-003-3 — Transmission Vegetation Management
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by an applicable Transmission Owner or applicable Generator Owner or Reliability
Coordinator to protect an Interconnection may cause excessive sagging and an outage. Another
example would be ice loading beyond the line’s Rating and Rated Electrical Operating
Condition. Such vegetation-related encroachments and outages are not violations of this
standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
Draft 4: April 23, 2012
22
FAC-003-3 — Transmission Vegetation Management
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of an applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the applicable TO or applicable GO
should use the next largest clearance distance based on the next highest nominal voltage in the
table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, an applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
Draft 4: April 23, 2012
23
FAC-003-3 — Transmission Vegetation Management
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
Draft 4: April 23, 2012
24
FAC-003-3 — Transmission Vegetation Management
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner or applicable Generator Owner employee who
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
Draft 4: April 23, 2012
25
FAC-003-3 — Transmission Vegetation Management
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Requirement R7:
Draft 4: April 23, 2012
26
FAC-003-3 — Transmission Vegetation Management
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies
1,000 miles of applicable transmission lines to be completed in the applicable Transmission
Owner’s or applicable Generator Owner’s annual plan, the applicable Transmission Owner or
applicable Generator Owner will be responsible completing those identified miles. If a
applicable Transmission Owner or applicable Generator Owner makes a modification to the
annual plan that does not put the transmission system at risk of an encroachment the annual plan
may be modified. If 100 miles of the annual plan is deferred until next year the calculation to
determine what percentage was completed for the current year would be: 1000 – 100 (deferred
miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner only completed 875 of the total
1000 miles with no acceptable documentation for modification of the annual plan the calculation
for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete
then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
Draft 4: April 23, 2012
27
FAC-003-3 — Transmission Vegetation Management
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Draft 4: April 23, 2012
28
FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 9
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
9
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 4: April 23, 2012
29
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 4: April 23, 2012
30
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Draft 4: April 23, 2012
31
FAC-003-3 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an in-
Draft 4: April 23, 2012
32
FAC-003-3 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Draft 4: April 23, 2012
33
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 4: April 23, 2012
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
34
FAC-003-3 — Transmission Vegetation Management
Effe c tive Da te s
There are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In
those jurisdictions where no regulatory approval is required, Requirement R3 becomes
effective on the first day of the first calendar quarter one year following Board of Trustees’
adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
Draft 34: March 6April 23, 2012
1
FAC-003-3 — Transmission Vegetation Management
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 34: March 6April 23, 2012
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
2
FAC-003-3 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
The Project 2010-07 team further modified that
construction documents, pre-2007 vegetation
proposed definition to include applicable
maintenance records, or by the blowout standard in
Generator Owners.
effect when the line was built. The ROW width in
no case exceeds the applicable Transmission
Owner’s or applicable Generator Owner’s legal rights but may be less based on the
aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those vegetation
conditions under the applicable Transmission
Owner’s or applicable Generator Owner’s control
that are likely to pose a hazard to the line(s) prior to
the next planned maintenance or inspection. This
may be combined with a general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
The Project 2010-07 team further modified that
proposed definition to include applicable
Generator Owners.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance
(MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Draft 34: March 6April 23, 2012
3
FAC-003-3 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by
the NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume
that FAC-003-2 will be approved by FERC and other governmental authorities. Thus, the
Project 2010-07 drafting team has developed two sets of proposed changes: one to this version,
FAC-003-2, the version developed by the Project 2007-07 team and adopted by NERC’s Board
of Trustees, and one to FAC-003-1, the current FERC-approved version of the standard.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-3
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.
Applicable Transmission Owners
4.1.1.1 Transmission Owners that own Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own
generation Facilities defined in 4.3
4.2.
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands
owned by federal 1, state, provincial, public,
private, or tribal entities:
4.2. 1 Each overhead transmission line operated
at 200kV or higher.
1
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing process
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) Specifically
addressing the areas where the standard
does and does not apply makes the
standard clearer.
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Draft 34: March 6April 23, 2012
4
FAC-003-3 — Transmission Vegetation Management
4.2.2 Each overhead transmission line operated below 200kV identified as an element
of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3 Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4 Each overhead transmission line identified above (4.2.1 through 4.2.3) located
outside the fenced area of the switchyard, station or substation and any portion of the
span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1 Overhead transmission lines that (1) extend
Standard FAC-003-3, “transmission
line(s) and “applicable line(s) can
greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station
also refer to the generation Facilities
as referenced in 4.3 and its
switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a
subsections.
clear line of sight 3 from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Draft 34: March 6April 23, 2012
5
FAC-003-3 — Transmission Vegetation Management
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
a) Performance-based defines a particular reliability objective or outcome to be
achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b) Risk-based preventive requirements to reduce the risks of failure to acceptable
tolerance levels. A risk-based reliability requirement should be framed as: who,
under what conditions (if any), shall perform what action, to achieve what particular
result or outcome that reduces a stated risk to the reliability of the bulk power
system?
c) Competency-based defines a minimum set of capabilities an entity needs to
have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
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6
FAC-003-3 — Transmission Vegetation Management
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
Performance-based: Requirements 1 and 2
Competency-based: Requirement 3
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
Draft 34: March 6April 23, 2012
7
FAC-003-3 — Transmission Vegetation Management
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Draft 34: March 6April 23, 2012
8
FAC-003-3 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 4 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage 5,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage 6,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetationrelated Sustained Outage4.
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
M1. Each applicable Transmission Owner
4
This requirement does not apply to circumstances that are beyond the control of an applicable Transmission Owner
or applicable Generator Owner subject to this reliability standard, including natural disasters such as earthquakes,
fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the applicable
Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and floods; human
or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation, removal, or
digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to
exercise its full legal rights on the ROW.
5
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Draft 34: March 6April 23, 2012
9
FAC-003-3 — Transmission Vegetation Management
and applicable Generator Owner has evidence that it managed vegetation to prevent
encroachment into the MVCD as described in R1. Examples of acceptable forms of
evidence may include dated attestations, dated reports containing no Sustained Outages
associated with encroachment types 2 through 4 above, or records confirming no Realtime observations of any MVCD encroachments. (R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
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10
FAC-003-3 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
1 for an illustration of possible conductor
vegetation growth rates, vegetation
locations.
control methods, and inspection
frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
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11
FAC-003-3 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders, documentation of constraints from landowners, court
orders, inspection records of increased monitoring, documentation of the de-rating of
lines, revised work orders, invoices, or
Rationale
evidence that the line was de-energized.
Inspections are used by applicable
(R5)
Transmission Owners and applicable
Generator Owners to assess the condition of
the entire ROW. The information from the
assessment can be used to determine risk,
determine future work and evaluate
R6. Each applicable Transmission Owner and
recently-completed work. This requirement
applicable Generator Owner shall perform
sets a minimum Vegetation Inspection
a Vegetation Inspection of 100% of its
frequency of once per calendar year but
applicable transmission lines (measured in
with no more than 18 months between
units of choice - circuit, pole line, line
inspections on the same ROW. Based upon
miles or kilometers, etc.) at least once per
average growth rates across North America
calendar year and with no more than 18
and on common utility practice, this
calendar months between inspections on
minimum frequency is reasonable.
the same ROW 7 [Violation Risk Factor:
Transmission Owners should consider local
and environmental factors that could
7
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
Draft 34: March 6April 23, 2012
12
FAC-003-3 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of an applicable Transmission Owner or
applicable Generator Owner 8
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
8
Circumstances that are beyond the control of an applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Draft 34: March 6April 23, 2012
13
FAC-003-3 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance enforcement authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcement Authority.
1.11.2
Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.21.3
Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Draft 34: March 6April 23, 2012
14
FAC-003-3 — Transmission Vegetation Management
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.31.4
Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
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15
FAC-003-3 — Transmission Vegetation Management
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
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16
FAC-003-3 — Transmission Vegetation Management
Table of Compliance Elements
R#
R1
Time
Horizon
Real-time
VRF
Violation Severity Level
Lower
High
Moderate
High
Severe
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line identified as an
element of an IROL or Major
WECC transfer path and a
vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
R2
Real-time
Medium
Draft 34: March 6April 23, 2012
The responsible entity failed to
manage vegetation to prevent
encroachment into the MVCD
of a line not identified as an
element of an IROL or Major
WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
17
A grow-in
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
FAC-003-3 — Transmission Vegetation Management
•
•
R3
R4
R5
Long-Term
Planning
Real-time
Operations
Planning
Lower
Medium
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the responsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
A grow-in
The responsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
responsible entity’s applicable
lines. Requirement R3, Part
3.1)
The responsible entity does not
have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
responsible entity’s applicable
lines.
The responsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The responsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
The responsible entity did not
take corrective action when it
was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
Draft 34: March 6April 23, 2012
active transmission line
ROW
Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
18
FAC-003-3 — Transmission Vegetation Management
R6
R7
Operations
Planning
Operations
Planning
Medium
The responsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The responsible entity failed
to inspect more than 5% up to
and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The responsible entity failed to
inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The responsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The responsible entity failed
to complete more than 5% and
up to and including 10% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The responsible entity failed to
complete more than 15% of its
annual vegetation work plan for
its applicable lines (as finally
modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
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19
FAC-003-3 — Transmission Vegetation Management
Guideline and Technical Basis
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by an applicable Transmission Owner or applicable Generator Owner from a third party
Draft 34: March 6April 23, 2012
20
FAC-003-3 — Transmission Vegetation Management
such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by an
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission Owner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to include Generator
Owners and to address the matter set forth in Paragraph 734 of FERC Order 693. The Order
pointed out that Transmission Owners may in some cases own more property or rights than are
needed to reliably operate transmission lines. This modified definition represents a slight but
significant departure from the strict legal definition of “right of way” in that this definition is based
on engineering and construction considerations that establish the width of a corridor from a
technical basis. The pre-2007 maintenance records are included in the revised definition to allow
the use of such vegetation widths if there were no engineering or construction standards that
referenced the width of right of way to be maintained for vegetation on a particular line but the
evidence exists in maintenance records for a width that was in fact maintained prior to this
standard becoming mandatory. Such widths may be the only information available for lines that
had limited or no vegetation easement rights and were typically maintained primarily to ensure
public safety. This standard does not require additional easement rights to be purchased to satisfy a
minimum right of way width that did not exist prior to this standard becoming mandatory.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to include Generator Owners
and to allow both maintenance inspections and vegetation inspections to be performed
concurrently. This allows potential efficiencies, especially for those lines with minimal vegetation
and/or slow vegetation growth rates.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
Draft 34: March 6April 23, 2012
21
FAC-003-3 — Transmission Vegetation Management
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Requirements R1 and R2:
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by an applicable Transmission Owner or applicable Generator Owner or Reliability
Coordinator to protect an Interconnection may cause excessive sagging and an outage. Another
example would be ice loading beyond the line’s Rating and Rated Electrical Operating
Condition. Such vegetation-related encroachments and outages are not violations of this
standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
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22
FAC-003-3 — Transmission Vegetation Management
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of an applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with an
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the applicable TO or applicable GO
should use the next largest clearance distance based on the next highest nominal voltage in the
table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, an applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach an
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
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23
FAC-003-3 — Transmission Vegetation Management
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of an applicable Transmission Owner or applicable Generator Owner employee who
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24
FAC-003-3 — Transmission Vegetation Management
personally identifies such a threat in the field. Confirmation could also be made by sending out
an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
Draft 34: March 6April 23, 2012
25
FAC-003-3 — Transmission Vegetation Management
•
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
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26
FAC-003-3 — Transmission Vegetation Management
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when an applicable Transmission Owner or applicable Generator Owner identifies
1,000 miles of applicable transmission lines to be completed in the applicable Transmission
Owner’s or applicable Generator Owner’s annual plan, the applicable Transmission Owner or
applicable Generator Owner will be responsible completing those identified miles. If a
applicable Transmission Owner or applicable Generator Owner makes a modification to the
annual plan that does not put the transmission system at risk of an encroachment the annual plan
may be modified. If 100 miles of the annual plan is deferred until next year the calculation to
determine what percentage was completed for the current year would be: 1000 – 100 (deferred
miles) = 900 modified annual plan, or 900 / 900 = 100% completed annual miles. If an
applicable Transmission Owner or applicable Generator Owner only completed 875 of the total
1000 miles with no acceptable documentation for modification of the annual plan the calculation
for failure to complete the annual plan would be: 1000 – 875 = 125 miles failed to complete
then, 125 miles (not completed) / 1000 total annual plan miles = 12.5% failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
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FAC-003-3 — Transmission Vegetation Management
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
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FAC-003-3 — Transmission Vegetation Management
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 9
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 10
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
9
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be
achieved at time of vegetation maintenance.
10
Where applicable lines are operated at nominal voltages other than those listed, the applicable Transmission Owner or applicable Generator Owner should use
the maximum system voltage to determine the appropriate clearance for that line.
Draft 34: March 6April 23, 2012
29
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Draft 34: March 6April 23, 2012
30
FAC-003-3 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Draft 34: March 6April 23, 2012
31
FAC-003-3 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an in-
Draft 34: March 6April 23, 2012
32
FAC-003-3 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Draft 34: March 6April 23, 2012
33
FAC-003-3 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Over-voltage
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Draft 34: March 6April 23, 2012
Transient
Clearance (ft.)
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
34
FAC-003-23 — Transmission Vegetation Management
Effe c tive Da te s
ThisThere are two effective dates associated with this standard.
The first effective date allows Generator Owners time to develop documented maintenance
strategies or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to
the Generator Owner becomes effective on the first calendar day of the first calendar
quarter one year after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required.
Where In those jurisdictions where no regulatory approval is required, the
standardRequirement R3 becomes effective on the first calendar day of the first calendar
quarter one year afterfollowing Board of TrusteesTrustees’ adoption. or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Requirement
R1 – R7
Jurisdiction
Alberta
British
Columbia
Manitoba
New
Brunswick
Newfoundland
Nova
Scotia
Ontario
TBD
TBD
TBD
TBD
TBD
TBD
TBD
(All Req.)
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6,
and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4,
R5, R6, and R7 applied to the Generator Owner become effective on the first calendar
day of the first calendar quarter two years after the date of the order approving the
standard from applicable regulatory authorities where such explicit approval for all
requirements is required. In those jurisdictions where no regulatory approval is required,
Requirements R1, R2, R4, R5, R6, and R7 become effective on the first day of the first
calendar quarter two years following Board of Trustees’ adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of
an Interconnection Reliability Operating Limit (IROL) or designated by the Western
Electricity Coordinating Council (WECC) as an element of a Major WECC Transfer
Path, becomes subject to this standard the latter of: 1) 12 months after the date the
Planning Coordinator or WECC initially designates the line as being an element of an
Draft 4: April 23, 2012
1
Queb
TBD
FAC-003-23 — Transmission Vegetation Management
IROL or an element of a Major WECC Transfer Path, or 2) January 1 of the planning
year when the line is forecast to become an element of an IROL or an element of a Major
WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element
of an IROL or a Major WECC Transfer Path which has a specified date for the removal
of such designation will no longer be subject to this standard effective on that specified
date.
3. A line operated at 200 kV or above, currently subject to this standard which is a
designated element of an IROL or a Major WECC Transfer Path and which has a
specified date for the removal of such designation will be subject to Requirement R2 and
no longer be subject to Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an
asset owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date.
5. An existing transmission line operated below 200kV which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this
standard 12 months after the acquisition date of the line if at the time of acquisition the
line is designated by the Planning Coordinator as an element of an IROL or by WECC as
an element of a Major WECC Transfer Path.
Ve rs io n His to ry
Version
3
Date
September 29,
2011
Draft 4: April 23, 2012
Action
Change Tracking
Using the latest draft of FAC-003-2
Revision under Project
from the Project 2007-07 SDT, modified 2010-07
proposed definitions and Applicability
to include Generator Owners of a certain
length.
2
FAC-003-23 — Transmission Vegetation Management
De fin itio n s o f Te rm s Us e d in S ta n da rd
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Right-of-Way (ROW)
The current glossary definition of this NERC
The corridor of land under a transmission line(s)
term is modified to address the issues set forth
needed to operate the line(s). The width of the
in Paragraph 734 of FERC Order 693.
corridor is established by engineering or
construction standards as documented in either
The Project 2010-07 team further modified that
construction documents, pre-2007 vegetation
proposed definition to include applicable
maintenance records, or by the blowout standard
Generator Owners.
in effect when the line was built. The ROW width
in no case exceeds the applicable Transmission Owner’s or applicable Generator Owner’s legal rights
but may be less based on the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation
conditions on a Right-of-Way and those
vegetation conditions under the applicable
Transmission Owner’s or applicable Generator
Owner’s control that are likely to pose a hazard to
the line(s) prior to the next planned maintenance
or inspection. This may be combined with a
general line inspection.
The current glossary definition of this NERC
term is modified to allow both maintenance
inspections and vegetation inspections to be
performed concurrently.
The Project 2010-07 team further modified that
proposed definition to include applicable
Generator Owners.
Current definition of Vegetation Inspection:
The systematic examination of a transmission
corridor to document vegetation conditions.
Minimum Vegetation Clearance Distance
(MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
3
FAC-003-23 — Transmission Vegetation Management
When this standard has received ballot approval, the text boxes will be moved to the Guideline
and Technical Basis Section.
FAC-003-2 was developed under Project 2007-07. The standard was balloted and adopted by
the NERC Board of Trustees, but the Project 2010-07 drafting team does not want to assume
that FAC-003-2 will be approved by FERC and other governmental authorities. Thus, the
Project 2010-07 drafting team has developed two sets of proposed changes: one to this version,
FAC-003-2, the version developed by the Project 2007-07 team and adopted by NERC’s Board
of Trustees, and one to FAC-003-1, the current FERC-approved version of the standard.
A. Introduction
1. Title:
Transmission Vegetation Management
2. Number:
FAC-003-23
3. Purpose:
To maintain a reliable electric transmission system by using a defense-indepth strategy to manage vegetation located on transmission rights of way
(ROW) and minimize encroachments from vegetation located adjacent to
the ROW, thus preventing the risk of those vegetation-related outages that
could lead to Cascading.
4. Applicability
4.1.
Functional Entities:
4.1.1.4.1.1.1. 4.1.1 Applicable
Transmission Owners
4.1.1.1 Transmission Owners that own
Transmission Facilities defined in 4.2.
4.1.2 Applicable Generator Owners
4.1.2.1 Generator Owners that own
generation Facilities defined in 4.3
4.2.
1
Transmission Facilities: Defined below
(referred to as “applicable lines”), including
but not limited to those that cross lands
owned by federal 1, state, provincial, public,
private, or tribal entities:
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
Rationale: The areas excluded in 4.2.4
were excluded based on comments from
industry for reasons summarized as
follows: 1) There is a very low risk from
vegetation in this area. Based on an
informal survey, no TOs reported such
an event. 2) Substations, switchyards,
and stations have many inspection and
maintenance activities that are necessary
for reliability. Those existing processes
manage the threat. As such, the formal
steps in this standard are not well suited
for this environment. 3) NERC has a
project in place to address at a later
date the applicability of this standard
to Generation Owners. 43)
Specifically addressing the areas where
the standard does and does not apply
makes the standard clearer.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
4
FAC-003-23 — Transmission Vegetation Management
4.2. 1 . Each overhead transmission line operated at 200kV or higher.
4.2.2 . Each overhead transmission line operated below 200kV identified as an
element of an IROL under NERC Standard FAC-014 by the Planning Coordinator.
4.2.3 . Each overhead transmission line operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
4.2.4 . Each overhead transmission line identified above (4.2.1 through 4.2.3)
located outside the fenced area of the switchyard, station or substation and any
portion of the span of the transmission line that is crossing the substation fence.
4.3.
Generation Facilities: Defined below (referred to as “applicable lines”),
including but not limited to those that cross lands owned by federal 2, state,
provincial, public, private, or tribal entities:
Within the text of NERC Reliability
4.3.1 Overhead transmission lines that (1) extend
Standard FAC-003-3, “transmission
greater than one mile or 1.609 kilometers beyond
line(s) and “applicable line(s) can
the fenced area of the generating station
also refer to the generation Facilities
switchyard to the point of interconnection with a
as referenced in 4.3 and its
Transmission Owner’s Facility or (2) do not have a
subsections.
3
clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s
Facility and are:
4.3.1.1 Operated at 200kV or higher; or
4.3.1.2 Operated below 200kV identified as an element of an IROL under NERC
Standard FAC-014 by the Planning Coordinator; or
4.3.1.3 Operated below 200 kV identified as an element of a Major WECC Transfer
Path in the Bulk Electric System by WECC.
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity to
certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the Reliability
Standard Requirement given the specific facts and circumstances of its use, ownership or
operation of the bulk power system.
2
EPAct 2005 section 1211c: “Access
approvals by Federal agencies.”
3
“Clear line of sight” means the distance that can be seen by the average person without special instrumentation
(e.g., binoculars, telescope, spyglasses, etc.) on a clear day.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
5
FAC-003-23 — Transmission Vegetation Management
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining satisfactory
performance nor to limit how an entity may demonstrate compliance if valid alternatives to
demonstrating compliance are available in a specific case. A Reliability Standard may be
enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new Requirements
under NERC’s Reliability Standards or to modify the Requirements in any existing NERC
Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
5. Background:
This standard uses three types of requirements to provide layers of protection to
prevent vegetation related outages that could lead to Cascading:
a)
Performance-based defines a particular reliability objective or outcome to
be achieved. In its simplest form, a results-based requirement has four components:
who, under what conditions (if any), shall perform what action, to achieve what
particular bulk power system performance result or outcome?
b)
Risk-based preventive requirements to reduce the risks of failure to
acceptable tolerance levels. A risk-based reliability requirement should be framed as:
who, under what conditions (if any), shall perform what action, to achieve what
particular result or outcome that reduces a stated risk to the reliability of the bulk
power system?
c)
Competency-based defines a minimum set of capabilities an entity needs
to have to demonstrate it is able to perform its designated reliability functions. A
competency-based reliability requirement should be framed as: who, under what
conditions (if any), shall have what capability, to achieve what particular result or
outcome to perform an action to achieve a result or outcome or to reduce a risk to the
reliability of the bulk power system?
The defense-in-depth strategy for reliability standards development recognizes that
each requirement in a NERC reliability standard has a role in preventing system
failures, and that these roles are complementary and reinforcing. Reliability
standards should not be viewed as a body of unrelated requirements, but rather should
be viewed as part of a portfolio of requirements designed to achieve an overall
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
6
FAC-003-23 — Transmission Vegetation Management
defense-in-depth strategy and comport with the quality objectives of a reliability
standard.
This standard uses a defense-in-depth approach to improve the reliability of the electric
Transmission system by:
• Requiring that vegetation be managed to prevent vegetation encroachment inside
the flash-over clearance (R1 and R2);
• Requiring documentation of the maintenance strategies, procedures, processes and
specifications used to manage vegetation to prevent potential flash-over
conditions including consideration of 1) conductor dynamics and 2) the
interrelationships between vegetation growth rates, control methods and the
inspection frequency (R3);
• Requiring timely notification to the appropriate control center of vegetation
conditions that could cause a flash-over at any moment (R4);
• Requiring corrective actions to ensure that flash-over distances will not be
violated due to work constrains such as legal injunctions (R5);
• Requiring inspections of vegetation conditions to be performed annually (R6);
and
• Requiring that the annual work needed to prevent flash-over is completed (R7).
For this standard, the requirements have been developed as follows:
Performance-based: Requirements 1 and 2
Competency-based: Requirement 3
Risk-based: Requirements 4, 5, 6 and 7
R3 serves as the first line of defense by ensuring that entities understand the problem
they are trying to manage and have fully developed strategies and plans to manage the
problem. R1, R2, and R7 serve as the second line of defense by requiring that entities
carry out their plans and manage vegetation. R6, which requires inspections, may be
either a part of the first line of defense (as input into the strategies and plans) or as a
third line of defense (as a check of the first and second lines of defense). R4 serves as
the final line of defense, as it addresses cases in which all the other lines of defense
have failed.
Major outages and operational problems have resulted from interference between
overgrown vegetation and transmission lines located on many types of lands and
ownership situations. Adherence to the standard requirements for applicable lines on
any kind of land or easement, whether they are Federal Lands, state or provincial
lands, public or private lands, franchises, easements or lands owned in fee, will
reduce and manage this risk. For the purpose of the standard the term “public lands”
includes municipal lands, village lands, city lands, and a host of other governmental
entities.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
7
FAC-003-23 — Transmission Vegetation Management
This standard addresses vegetation management along applicable overhead lines and
does not apply to underground lines, submarine lines or to line sections inside an
electric station boundary.
This standard focuses on transmission lines to prevent those vegetation related
outages that could lead to Cascading. It is not intended to prevent customer outages
due to tree contact with lower voltage distribution system lines. For example,
localized customer service might be disrupted if vegetation were to make contact with
a 69kV transmission line supplying power to a 12kV distribution station. However,
this standard is not written to address such isolated situations which have little impact
on the overall electric transmission system.
Since vegetation growth is constant and always present, unmanaged vegetation poses
an increased outage risk, especially when numerous transmission lines are operating
at or near their Rating. This can present a significant risk of consecutive line failures
when lines are experiencing large sags thereby leading to Cascading. Once the first
line fails the shift of the current to the other lines and/or the increasing system loads
will lead to the second and subsequent line failures as contact to the vegetation under
those lines occurs. Conversely, most other outage causes (such as trees falling into
lines, lightning, animals, motor vehicles, etc.) are not an interrelated function of the
shift of currents or the increasing system loading. These events are not any more
likely to occur during heavy system loads than any other time. There is no causeeffect relationship which creates the probability of simultaneous occurrence of other
such events. Therefore these types of events are highly unlikely to cause large-scale
grid failures. Thus, this standard places the highest priority on the management of
vegetation to prevent vegetation grow-ins.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
8
FAC-003-23 — Transmission Vegetation Management
B. Requirements and Measures
R1. Each applicable Transmission Owner
and applicable Generator Owner shall
manage vegetation to prevent
encroachments into the MVCD of its
applicable line(s) which are either an
element of an IROL, or an element of
a Major WECC Transfer Path;
operating within their Rating and all
Rated Electrical Operating Conditions
of the types shown below 4 [Violation
Risk Factor: High] [Time Horizon:
Real-time]:
1.
An encroachment into the
MVCD as shown in FAC-003Table 2, observed in Real-time,
absent a Sustained Outage, 56,
2.
An encroachment due to a fall-in
from inside the ROW that caused
a vegetation-related Sustained
Outage, 78,
3.
An encroachment due to the
blowing together of applicable
lines and vegetation located
inside the ROW that caused a
vegetation-related Sustained
Outage,4Outage4,
4.
An encroachment due to
vegetation growth into the
MVCD that caused a vegetation-
Rationale for R1 and R2:
Lines with the highest significance to reliability
are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage
vegetation which are listed in order of increasing
degrees of severity in non-compliant performance
as it relates to a failure of an applicable
Transmission Owner's or applicable Generator
Owner’s vegetation maintenance program:
1. This management failure is found by routine
inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in
an otherwise sound program.
2. This management failure occurs when the
height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side
growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative
of a program that is not addressing the most
fundamental dynamic of vegetation management,
(i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a
mechanism for a Cascade.
4
This requirement does not apply to circumstances that are beyond the control of aan applicable Transmission
Owner or applicable Generator Owner subject to this reliability standard, including natural disasters such as
earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the
applicable Transmission Owner or applicable Generator Owner or an applicable regulatory body, ice storms, and
floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, or installation,
removal, or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s
right to exercise its full legal rights on the ROW.
wner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
6
If a later confirmation of a Fault by the applicable Transmission Owner or applicable Generator Owner shows that
a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be
considered the equivalent of a Real-time observation.
8
Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage
regardless of the actual number of outages within a 24-hour period.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
9
FAC-003-23 — Transmission Vegetation Management
related Sustained Outage.4Outage4.
M1. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R1.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R1)
R2. Each applicable Transmission Owner and applicable Generator Owner shall manage
vegetation to prevent encroachments into the MVCD of its applicable line(s) which are
not either an element of an IROL, or an element of a Major WECC Transfer Path;
operating within its Rating and all Rated Electrical Operating Conditions of the types
shown below2 [Violation Risk Factor: Medium] [Time Horizon: Real-time]:
1. An encroachment into the MVCD, observed in Real-time, absent a Sustained
Outage,3Outage3,
2. An encroachment due to a fall-in from inside the ROW that caused a vegetationrelated Sustained Outage,4Outage4,
3. An encroachment due to blowing together of applicable lines and vegetation located
inside the ROW that caused a vegetation-related Sustained Outage,4Outage4,
4. An encroachment due to vegetation growth into the line MVCD that caused a
vegetation-related Sustained Outage4
M2. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it managed vegetation to prevent encroachment into the MVCD as described in R2.
Examples of acceptable forms of evidence may include dated attestations, dated reports
containing no Sustained Outages associated with encroachment types 2 through 4
above, or records confirming no Real-time observations of any MVCD encroachments.
(R2)
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
10
FAC-003-23 — Transmission Vegetation Management
R3. Each applicable Transmission Owner
Rationale
and applicable Generator Owner shall
The documentation provides a basis for
have documented maintenance strategies
evaluating the competency of the applicable
or procedures or processes or
Transmission Owner’s or applicable
specifications it uses to prevent the
Generator Owner’s vegetation program.
encroachment of vegetation into the
There may be many acceptable approaches
MVCD of its applicable lines that
to maintain clearances. Any approach must
accounts for the following:
demonstrate that the applicable
3.1 Movement of applicable line
Transmission Owner or applicable
conductors under their Rating and
Generator Owner avoids vegetation-to-wire
all Rated Electrical Operating
conflicts under all Ratings and all Rated
Conditions;
Electrical Operating Conditions. See Figure
3.2 Inter-relationships between
1 for an illustration of possible conductor
vegetation growth rates, vegetation
locations.
control methods, and inspection
frequency.
[Violation Risk Factor: Lower] [Time Horizon: Long Term
Planning]:
M3. The maintenance strategies or procedures or processes or specifications provided
demonstrate that the applicable Transmission Owner and applicable Generator Owner
can prevent encroachment into the MVCD considering the factors identified in the
requirement. (R3)
R4. Each applicable Transmission Owner
Rationale
and applicable Generator Owner,
This is to ensure expeditious communication
without any intentional time delay, shall
between the applicable Transmission Owner or
notify the control center holding
applicable Generator Owner and the control
switching authority for the associated
center when a critical situation is confirmed.
applicable line when the applicable
Transmission Owner and applicable
Generator Owner has confirmed the existence of a vegetation condition that is likely to
cause a Fault at any moment [Violation Risk Factor: Medium] [Time Horizon: Realtime].
M4. Each applicable Transmission Owner and applicable Generator Owner that has a
confirmed vegetation condition likely to cause a Fault at any moment will have
evidence that it notified the control center holding switching authority for the
associated transmission line without any intentional time delay. Examples of evidence
may include control center logs, voice recordings, switching orders, clearance orders
and subsequent work orders. (R4)
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
11
FAC-003-23 — Transmission Vegetation Management
R5. When a applicable Transmission Owner
and applicable Generator Owner is
constrained from performing vegetation
work on an applicable line operating
within its Rating and all Rated Electrical
Operating Conditions, and the constraint
may lead to a vegetation encroachment
into the MVCD prior to the
implementation of the next annual work
plan, then the applicable Transmission
Owner or applicable Generator Owner
shall take corrective action to ensure
continued vegetation management to
prevent encroachments [Violation Risk
Factor: Medium] [Time Horizon:
Operations Planning].
Rationale
Legal actions and other events may occur
which result in constraints that prevent the
applicable Transmission Owner or
applicable Generator Owner from
performing planned vegetation maintenance
work.
In cases where the transmission line is put at
potential risk due to constraints, the intent is
for the applicable Transmission Owner and
applicable Generator Owner to put interim
measures in place, rather than do nothing.
The corrective action process is not
intended to address situations where a
planned work methodology cannot be
performed but an alternate work
methodology can be used.
M5. Each applicable Transmission Owner and applicable Generator Owner has evidence of
the corrective action taken for each constraint where an applicable transmission line
was put at potential risk. Examples of acceptable forms of evidence may include
initially-planned work orders,
documentation of constraints from
Rationale
landowners, court orders, inspection
Inspections are used by applicable
records of increased monitoring,
Transmission Owners and applicable
documentation of the de-rating of lines,
Generator Owners to assess the condition of
revised work orders, invoices, or evidence
the entire ROW. The information from the
that the line was de-energized. (R5)
assessment can be used to determine risk,
determine future work and evaluate
recently-completed work. This requirement
sets a minimum Vegetation Inspection
frequency of once per calendar year but
R6. Each applicable Transmission Owner and
with no more than 18 months between
applicable Generator Owner shall perform
inspections on the same ROW. Based upon
a Vegetation Inspection of 100% of its
average growth rates across North America
applicable transmission lines (measured in
and on common utility practice, this
units of choice - circuit, pole line, line
minimum frequency is reasonable.
miles or kilometers, etc.) at least once per
Transmission Owners should consider local
calendar year and with no more than 18
and environmental factors that could
calendar months between inspections on
warrant more frequent inspections.
the same ROW 9 [Violation Risk Factor:
9
When the applicable Transmission Owner or applicable Generator Owner is prevented from performing a
Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO or GO is granted a time extension
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
12
FAC-003-23 — Transmission Vegetation Management
Medium] [Time Horizon: Operations Planning].
M6. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it conducted Vegetation Inspections of the transmission line ROW for all
applicable lines at least once per calendar year but with no more than 18 calendar
months between inspections on the same ROW. Examples of acceptable forms of
evidence may include completed and dated work orders, dated invoices, or dated
inspection records. (R6)
R7. Each applicable Transmission Owner and
applicable Generator Owner shall complete
Rationale
100% of its annual vegetation work plan of
This requirement sets the expectation
applicable lines to ensure no vegetation
that the work identified in the annual
encroachments occur within the MVCD.
work plan will be completed as planned.
Modifications to the work plan in response
It allows modifications to the planned
to changing conditions or to findings from
work for changing conditions, taking into
vegetation inspections may be made
consideration anticipated growth of
(provided they do not allow encroachment
vegetation and all other environmental
of vegetation into the MVCD) and must be
factors, provided that those modifications
documented. The percent completed
do not put the transmission system at risk
calculation is based on the number of units
of a vegetation encroachment.
actually completed divided by the number
of units in the final amended plan
(measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples
of reasons for modification to annual plan may include [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]:
•
•
•
•
•
•
•
•
•
Change in expected growth rate/ environmental factors
Circumstances that are beyond the control of aan applicable Transmission Owner
or applicable Generator Owner 10
Rescheduling work between growing seasons
Crew or contractor availability/ Mutual assistance agreements
Identified unanticipated high priority work
Weather conditions/Accessibility
Permitting delays
Land ownership changes/Change in land use by the landowner
Emerging technologies
that is equivalent to the duration of the time the TO or GO was prevented from performing the Vegetation
Inspection.
10
Circumstances that are beyond the control of aan applicable Transmission Owner or applicable Generator Owner
include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, ice storms,
floods, or major storms as defined either by the TO or GO or an applicable regulatory body.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
13
FAC-003-23 — Transmission Vegetation Management
M7. Each applicable Transmission Owner and applicable Generator Owner has evidence
that it completed its annual vegetation work plan for its applicable lines. Examples of
acceptable forms of evidence may include a copy of the completed annual work plan
(as finally modified), dated work orders, dated invoices, or dated inspection records.
(R7)
C. Compliance
1. Compliance Monitoring Process
1.1 Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance enforcement authority unless the
applicable entity is owned, operated, or controlled by the Regional Entity. In such
cases the ERO or a Regional entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
For NERC, a third-party monitor without vested interest in the outcome for
NERC shall serve as the Compliance Enforcement Authority.
1.2 Regional Entity Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7,
Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed
by its Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
The applicable Transmission Owner and applicable Generator Owner retains data
or evidence to show compliance with Requirement R4, Measure M4 for most
recent 12 months of operator logs or most recent 3 months of voice recordings or
transcripts of voice recordings, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3 Compliance Monitoring and Enforcement Processes:
Compliance Audit
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
14
FAC-003-23 — Transmission Vegetation Management
Self-Certification
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
Periodic Data Submittal
1.4 Additional Compliance Information
Periodic Data Submittal: The applicable Transmission Owner and applicable
Generator Owner will submit a quarterly report to its Regional Entity, or the
Regional Entity’s designee, identifying all Sustained Outages of applicable lines
operated within their Rating and all Rated Electrical Operating Conditions as
determined by the applicable Transmission Owner or applicable Generator Owner
to have been caused by vegetation, except as excluded in footnote 2, and
including as a minimum the following:
o The name of the circuit(s), the date, time and duration of the outage;
the voltage of the circuit; a description of the cause of the outage; the
category associated with the Sustained Outage; other pertinent
comments; and any countermeasures taken by the applicable
Transmission Owner or applicable Generator Owner.
A Sustained Outage is to be categorized as one of the following:
o Category 1A — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, that are identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 1B — Grow-ins: Sustained Outages caused by vegetation
growing into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, by vegetation inside and/or
outside of the ROW;
o Category 2A — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 2B — Fall-ins: Sustained Outages caused by vegetation
falling into applicable lines, but are not identified as an element of an
IROL or Major WECC Transfer Path, from within the ROW;
o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling
into applicable lines from outside the ROW;
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
15
FAC-003-23 — Transmission Vegetation Management
o Category 4A — Blowing together: Sustained Outages caused by
vegetation and applicable lines that are identified as an element of an
IROL or Major WECC Transfer Path, blowing together from within
the ROW.
o Category 4B — Blowing together: Sustained Outages caused by
vegetation and applicable lines, but are not identified as an element of
an IROL or Major WECC Transfer Path, blowing together from within
the ROW.
The Regional Entity will report the outage information provided by applicable
Transmission Owners and applicable Generator Owners, as per the above,
quarterly to NERC, as well as any actions taken by the Regional Entity as a result
of any of the reported Sustained Outages.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
16
FAC-003-23 — Transmission Vegetation Management
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Level
Lower
N/A
R1
Real-time
Moderate
N/A
High
High
Severe
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as
an element of an IROL or
Major WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
absent a Sustained Outage.
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line identified as
an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
N/A
R2
Real-time
N/A
Medium
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
encroachment into the MVCD
as identified in FAC-003-Table
2 was observed in real time
17
A grow-in
The Transmission
Ownerresponsible entity failed
to manage vegetation to
prevent encroachment into the
MVCD of a line not identified
as an element of an IROL or
Major WECC transfer path and
a vegetation-related Sustained
Outage was caused by one of
FAC-003-23 — Transmission Vegetation Management
absent a Sustained Outage.
the following:
• A fall-in from inside the
active transmission line
ROW
• Blowing together of
applicable lines and
vegetation located inside
the active transmission line
ROW
•
N/A
R3
R4
Long-Term
Planning
Real-time
Lower
Medium
N/A
A grow-in
The Transmission
Ownerresponsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
inter-relationships between
vegetation growth rates,
vegetation control methods,
and inspection frequency, for
the Transmission
Owner’sresponsible entity’s
applicable lines. (Requirement
R3, Part 3.2)
The Transmission
Ownerresponsible entity has
maintenance strategies or
documented procedures or
processes or specifications but
has not accounted for the
movement of transmission line
conductors under their Rating
and all Rated Electrical
Operating Conditions, for the
Transmission
Owner’sresponsible entity’s
applicable lines. Requirement
R3, Part 3.1)
The Transmission
Ownerresponsible entity does
not have any maintenance
strategies or documented
procedures or processes or
specifications used to prevent
the encroachment of vegetation
into the MVCD, for the
Transmission
Owner’sresponsible entity’s
applicable lines.
N/A
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and notified
the control center holding
switching authority for that
applicable line, but there was
intentional delay in that
notification.
The Transmission
Ownerresponsible entity
experienced a confirmed
vegetation threat and did not
notify the control center
holding switching authority for
that applicable line.
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18
FAC-003-23 — Transmission Vegetation Management
R5
R6
R7
Operations
Planning
Operations
Planning
Operations
Planning
The Transmission
Ownerresponsible entity did
not take corrective action when
it was constrained from
performing planned vegetation
work where an applicable line
was put at potential risk.
Medium
N/A
N/A
N/A
Medium
The Transmission
Ownerresponsible entity
failed to inspect 5% or less
of its applicable lines
(measured in units of
choice - circuit, pole line,
line miles or kilometers,
etc.)
The Transmission
Ownerresponsible entity
failed to inspect more than 5%
up to and including 10% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission
Ownerresponsible entity failed
to inspect more than 10% up to
and including 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
The Transmission
Ownerresponsible entity failed
to inspect more than 15% of its
applicable lines (measured in
units of choice - circuit, pole
line, line miles or kilometers,
etc.).
Medium
The Transmission
Ownerresponsible entity
failed to complete 5% or
less of its annual
vegetation work plan for
its applicable lines (as
finally modified).
The Transmission
Ownerresponsible entity
failed to complete more than
5% and up to and including
10% of its annual vegetation
work plan for its applicable
lines (as finally modified).
The Transmission
Ownerresponsible entity failed
to complete more than 10% and
up to and including 15% of its
annual vegetation work plan
for its applicable lines (as
finally modified).
The Transmission
Ownerresponsible entity failed
to complete more than 15% of
its annual vegetation work plan
for its applicable lines (as
finally modified).
D. Re g io n a l Diffe re n c e s
None.
E. In te rp re ta tio n s
None.
F. As s o c ia te d Do c u m e nts
Guideline and Technical Basis (attached).
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
19
FAC-003-23 — Transmission Vegetation Management
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20
FAC-003-23 — Transmission Vegetation Management
Guideline and Technical Basis
Enforcement:
The Requirements within a Reliability Standard govern and will be enforced. The Requirements
within a Reliability Standard define what an entity must do to be compliant and binds an entity
to certain obligations of performance under Section 215 of the Federal Power Act. Compliance
will in all cases be measured by determining whether a party met or failed to meet the
Reliability Standard Requirement given the specific facts and circumstances of its use,
ownership or operation of the bulk power system.
Measures provide guidance on assessing non-compliance with the Requirements. Measures are
the evidence that could be presented to demonstrate compliance with a Reliability Standard
Requirement and are not intended to contain the quantitative metrics for determining
satisfactory performance nor to limit how an entity may demonstrate compliance if valid
alternatives to demonstrating compliance are available in a specific case. A Reliability Standard
may be enforced in the absence of specified Measures.
Entities must comply with the “Compliance” section in its entirety, including the Administrative
Procedure that sets forth, among other things, reporting requirements.
The “Guideline and Technical Basis” section, the Background section and text boxes with
“Examples” and “Rationale” are provided for informational purposes. They are designed to
convey guidance from NERC’s various activities. The “Guideline and Technical Basis” section
and text boxes with “Examples” and “Rationale” are not intended to establish new
Requirements under NERC’s Reliability Standards or to modify the Requirements in any existing
NERC Reliability Standard. Implementation of the “Guideline and Technical Basis” section, the
Background section and text boxes with “Examples” and “Rationale” is not a substitute for
compliance with Requirements in NERC’s Reliability Standards.”
Effective dates:
The first two sentences of the Effective Dates section is standard language used in most NERC
standards to cover the general effective date and is sufficient to cover the vast majority of
situations. Five special cases are needed to cover effective dates for individual lines which
undergo transitions after the general effective date. These special cases cover the effective dates
for those lines which are initially becoming subject to the standard, those lines which are
changing their applicability within the standard, and those lines which are changing in a manner
that removes their applicability to the standard.
Case 1 is needed because the Planning Coordinators may designate lines below 200 kV to
become elements of an IROL or Major WECC Transfer Path in a future Planning Year (PY).
For example, studies by the Planning Coordinator in 2011 may identify a line to have that
designation beginning in PY 2021, ten years after the planning study is performed. It is not
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
21
FAC-003-23 — Transmission Vegetation Management
intended for the Standard to be immediately applicable to, or in effect for, that line until that
future PY begins. The effective date provision for such lines ensures that the line will become
subject to the standard on January 1 of the PY specified with an allowance of at least 12 months
for the applicable Transmission Owner or applicable Generator Owner to make the necessary
preparations to achieve compliance on that line. The table below has some explanatory
examples of the application.
Date that Planning
Study is
completed
05/15/2011
05/15/2011
05/15/2011
05/15/2011
PY the line
will become
an IROL
element
2012
2013
2014
2021
Date 1
05/15/2012
05/15/2012
05/15/2012
05/15/2012
Date 2
01/01/2012
01/01/2013
01/01/2014
01/01/2021
Effective Date
The latter of Date 1
or Date 2
05/15/2012
01/01/2013
01/01/2014
01/01/2021
Case 2 is needed because a line operating below 200kV designated as an element of an IROL or
Major WECC Transfer Path may be removed from that designation due to system improvements,
changes in generation, changes in loads or changes in studies and analysis of the network.
Case 3 is needed because a line operating at 200 kV or above that once was designated as an
element of an IROL or Major WECC Transfer Path may be removed from that designation due
to system improvements, changes in generation, changes in loads or changes in studies and
analysis of the network. Such changes result in the need to apply R1 to that line until that date is
reached and then to apply R2 to that line thereafter.
Case 4 is needed because an existing line that is to be operated at 200 kV or above can be
acquired by aan applicable Transmission Owner or applicable Generator Owner from a third
party such as a Distribution Provider or other end-user who was using the line solely for local
distribution purposes, but the applicable Transmission Owner or applicable Generator Owner,
upon acquisition, is incorporating the line into the interconnected electrical energy transmission
network which will thereafter make the line subject to the standard.
Case 5 is needed because an existing line that is operated below 200 kV can be acquired by aan
applicable Transmission Owner or applicable Generator Owner from a third party such as a
Distribution Provider or other end-user who was using the line solely for local distribution
purposes, but the applicable Transmission ownerOwner or applicable Generator Owner, upon
acquisition, is incorporating the line into the interconnected electrical energy transmission
network. In this special case the line upon acquisition was designated as an element of an
Interconnection Reliability Operating Limit (IROL) or an element of a Major WECC Transfer
Path.
Defined Terms:
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
22
FAC-003-23 — Transmission Vegetation Management
Explanation for revising the definition of ROW:
The current NERC glossary definition of Right of Way has been modified to address the matter set
forth in Paragraph 734 of FERC Order 693. The Order pointed out that Transmission Owners may
in some cases own more property or rights than are needed to reliably operate transmission lines.
This modified definition represents a slight but significant departure from the strict legal definition
of “right of way” in that this definition is based on engineering and construction considerations
that establish the width of a corridor from a technical basis. The pre-2007 maintenance records are
included in the revised definition to allow the use of such vegetation widths if there were no
engineering or construction standards that referenced the width of right of way to be maintained
for vegetation on a particular line but the evidence exists in maintenance records for a width that
was in fact maintained prior to this standard becoming mandatory. Such widths may be the only
information available for lines that had limited or no vegetation easement rights and were typically
maintained primarily to ensure public safety. This standard does not require additional easement
rights to be purchased to satisfy a minimum right of way width that did not exist prior to this
standard becoming mandatory.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation for revising the definition of Vegetation Inspections:
The current glossary definition of this NERC term is being modified to allow both maintenance
inspections and vegetation inspections to be performed concurrently. This allows potential
efficiencies, especially for those lines with minimal vegetation and/or slow vegetation growth
rates.
The Project 2010-07 team further modified that proposed definition to include applicable
Generator Owners.
Explanation of the definition of the MVCD:
The MVCD is a calculated minimum distance that is derived from the Gallet Equations. This is a
method of calculating a flash over distance that has been used in the design of high voltage
transmission lines. Keeping vegetation away from high voltage conductors by this distance will
prevent voltage flash-over to the vegetation. See the explanatory text below for Requirement R3
and associated Figure 1. Table 2 below provides MVCD values for various voltages and altitudes.
Details of the equations and an example calculation are provided in Appendix 1 of the Technical
Reference Document.
Guidelines:
Requirements R1 and R2:
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
23
FAC-003-23 — Transmission Vegetation Management
R1 and R2 are performance-based requirements. The reliability objective or outcome to be
achieved is the management of vegetation such that there are no vegetation encroachments within
a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements;
however, they apply to different Facilities. Both R1 and R2 require each applicable Transmission
Owner or applicable Generator Owner to manage vegetation to prevent encroachment within the
MVCD of transmission lines. R1 is applicable to lines that are identified as an element of an IROL
or Major WECC Transfer Path. R2 is applicable to all other lines that are not elements of IROLs,
and not elements of Major WECC Transfer Paths.
The separation of applicability (between R1 and R2) recognizes that inadequate vegetation
management for an applicable line that is an element of an IROL or a Major WECC Transfer
Path is a greater risk to the interconnected electric transmission system than applicable lines that
are not elements of IROLs or Major WECC Transfer Paths. Applicable lines that are not
elements of IROLs or Major WECC Transfer Paths do require effective vegetation management,
but these lines are comparatively less operationally significant. As a reflection of this difference
in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for
R2.
Requirements R1 and R2 state that if inadequate vegetation management allows vegetation to
encroach within the MVCD distance as shown in Table 2, it is a violation of the standard. Table
2 distances are the minimum clearances that will prevent spark-over based on the Gallet
equations as described more fully in the Technical Reference document.
These requirements assume that transmission lines and their conductors are operating within
their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating and
Rated Electrical Operating Condition (potentially in violation of other standards), the occurrence
of a clearance encroachment may occur solely due to that condition. For example, emergency
actions taken by aan applicable Transmission OperatorOwner or applicable Generator Owner or
Reliability Coordinator to protect an Interconnection may cause excessive sagging and an
outage. Another example would be ice loading beyond the line’s Rating and Rated Electrical
Operating Condition. Such vegetation-related encroachments and outages are not violations of
this standard.
Evidence of failures to adequately manage vegetation include real-time observation of a
vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related
encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a
vegetation-related encroachment resulting in a Sustained Outage due to the blowing together of
the lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting
in a Sustained Outage due to a grow-in. Faults which do not cause a Sustained outage and which
are confirmed to have been caused by vegetation encroachment within the MVCD are considered
the equivalent of a Real-time observation for violation severity levels.
With this approach, the VSLs for R1 and R2 are structured such that they directly correlate to the
severity of a failure of aan applicable Transmission Owner or applicable Generator Owner to
manage vegetation and to the corresponding performance level of the Transmission Owner’s
vegetation program’s ability to meet the objective of “preventing the risk of those vegetation
related outages that could lead to Cascading.” Thus violation severity increases with aan
applicable Transmission Owner’s or applicable Generator Owner’s inability to meet this goal and
its potential of leading to a Cascading event. The additional benefits of such a combination are
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
24
FAC-003-23 — Transmission Vegetation Management
that it simplifies the standard and clearly defines performance for compliance. A performancebased requirement of this nature will promote high quality, cost effective vegetation management
programs that will deliver the overall end result of improved reliability to the system.
Multiple Sustained Outages on an individual line can be caused by the same vegetation. For
example initial investigations and corrective actions may not identify and remove the actual
outage cause then another outage occurs after the line is re-energized and previous high
conductor temperatures return. Such events are considered to be a single vegetation-related
Sustained Outage under the standard where the Sustained Outages occur within a 24 hour period.
The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for
various altitudes and operating voltages that is used in the design of Transmission Facilities.
Keeping vegetation from entering this space will prevent transmission outages.
If the applicable Transmission Owner or applicable Generator Owner has applicable lines
operated at nominal voltage levels not listed in Table 2, then the TOapplicable TO or applicable
GO should use the next largest clearance distance based on the next highest nominal voltage in
the table to determine an acceptable distance.
Requirement R3:
R3 is a competency based requirement concerned with the maintenance strategies, procedures,
processes, or specifications, aan applicable Transmission Owner or applicable Generator Owner
uses for vegetation management.
An adequate transmission vegetation management program formally establishes the approach the
applicable Transmission Owner or applicable Generator Owner uses to plan and perform
vegetation work to prevent transmission Sustained Outages and minimize risk to the transmission
system. The approach provides the basis for evaluating the intent, allocation of appropriate
resources, and the competency of the applicable Transmission Owner or applicable Generator
Owner in managing vegetation. There are many acceptable approaches to manage vegetation
and avoid Sustained Outages. However, the applicable Transmission Owner or applicable
Generator Owner must be able to show the documentation of its approach and how it conducts
work to maintain clearances.
An example of one approach commonly used by industry is ANSI Standard A300, part 7.
However, regardless of the approach a utility uses to manage vegetation, any approach aan
applicable Transmission Owner or applicable Generator Owner chooses to use will generally
contain the following elements:
1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or
maximum vegetation height) to ensure that MVCD clearances are never violated.
2. the work methods that the applicable Transmission Owner or applicable Generator
Owner uses to control vegetation
3. a stated Vegetation Inspection frequency
4. an annual work plan
The conductor’s position in space at any point in time is continuously changing in reaction to a
number of different loading variables. Changes in vertical and horizontal conductor positioning
are the result of thermal and physical loads applied to the line. Thermal loading is a function of
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
25
FAC-003-23 — Transmission Vegetation Management
line current and the combination of numerous variables influencing ambient heat dissipation
including wind velocity/direction, ambient air temperature and precipitation. Physical loading
applied to the conductor affects sag and sway by combining physical factors such as ice and
wind loading. The movement of the transmission line conductor and the MVCD is illustrated in
Figure 1 below. In the Technical Reference document more figures and explanations of
conductor dynamics are provided.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
26
FAC-003-23 — Transmission Vegetation Management
Figure 1
A cross-section view of a single conductor at a given point along the span is
shown with six possible conductor positions due to movement resulting from
thermal and mechanical loading.
Requirement R4:
R4 is a risk-based requirement. It focuses on preventative actions to be taken by the applicable
Transmission Owner or applicable Generator Owner for the mitigation of Fault risk when a
vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation
conditions, without any intentional delay, to the control center holding switching authority for
that specific transmission line. Examples of acceptable unintentional delays may include
communication system problems (for example, cellular service or two-way radio disabled),
crews located in remote field locations with no communication access, delays due to severe
weather, etc.
Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in
the form of aan applicable Transmission Owner’sOwner or applicable Generator Owner
employee who personally identifies such a threat in the field. Confirmation could also be made
by sending out an employee to evaluate a situation reported by a landowner.
Vegetation-related conditions that warrant a response include vegetation that is near or
encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission
conductor (a fall-in issue). A knowledgeable verification of the risk would include an
assessment of the possible sag or movement of the conductor while operating between no-load
conditions and its rating.
The applicable Transmission Owner or applicable Generator Owner has the responsibility to
ensure the proper communication between field personnel and the control center to allow the
control center to take the appropriate action until or as the vegetation threat is relieved.
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27
FAC-003-23 — Transmission Vegetation Management
Appropriate actions may include a temporary reduction in the line loading, switching the line out
of service, or other preparatory actions in recognition of the increased risk of outage on that
circuit. The notification of the threat should be communicated in terms of minutes or hours as
opposed to a longer time frame for corrective action plans (see R5).
All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at
any moment. For example, some applicable Transmission Owners or applicable Generator
Owners may have a danger tree identification program that identifies trees for removal with the
potential to fall near the line. These trees would not require notification to the control center
unless they pose an immediate fall-in threat.
Requirement R5:
R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the
applicable Transmission Owner or applicable Generator Owner for the mitigation of Sustained
Outage risk when temporarily constrained from performing vegetation maintenance. The intent
of this requirement is to deal with situations that prevent the applicable Transmission Owner or
applicable Generator Owner from performing planned vegetation management work and, as a
result, have the potential to put the transmission line at risk. Constraints to performing
vegetation maintenance work as planned could result from legal injunctions filed by property
owners, the discovery of easement stipulations which limit the applicable Transmission Owner’s
or applicable Generator Owner’s rights, or other circumstances.
This requirement is not intended to address situations where the transmission line is not at
potential risk and the work event can be rescheduled or re-planned using an alternate work
methodology. For example, a land owner may prevent the planned use of chemicals on nonthreatening, low growth vegetation but agree to the use of mechanical clearing. In this case the
applicable Transmission Owner or applicable Generator Owner is not under any immediate time
constraint for achieving the management objective, can easily reschedule work using an alternate
approach, and therefore does not need to take interim corrective action.
However, in situations where transmission line reliability is potentially at risk due to a constraint,
the applicable Transmission Owner or applicable Generator Owner is required to take an interim
corrective action to mitigate the potential risk to the transmission line. A wide range of actions
can be taken to address various situations. General considerations include:
•
•
•
•
Identifying locations where the applicable Transmission Owner or applicable
Generator Owner is constrained from performing planned vegetation maintenance
work which potentially leaves the transmission line at risk.
Developing the specific action to mitigate any potential risk associated with not
performing the vegetation maintenance work as planned.
Documenting and tracking the specific action taken for the location.
In developing the specific action to mitigate the potential risk to the transmission line
the applicable Transmission Owner or applicable Generator Owner could consider
location specific measures such as modifying the inspection and/or maintenance
intervals. Where a legal constraint would not allow any vegetation work, the interim
corrective action could include limiting the loading on the transmission line.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
28
FAC-003-23 — Transmission Vegetation Management
•
The applicable Transmission Owner or applicable Generator Owner should document
and track the specific corrective action taken at each location. This location may be
indicated as one span, one tree or a combination of spans on one property where the
constraint is considered to be temporary.
Requirement R6:
R6 is a risk-based requirement. This requirement sets a minimum time period for completing
Vegetation Inspections. The provision that Vegetation Inspections can be performed in
conjunction with general line inspections facilitates a Transmission Owner’s ability to meet this
requirement. However, the applicable Transmission Owner or applicable Generator Owner may
determine that more frequent vegetation specific inspections are needed to maintain reliability
levels, based on factors such as anticipated growth rates of the local vegetation, length of the
local growing season, limited ROW width, and local rainfall. Therefore it is expected that some
transmission lines may be designated with a higher frequency of inspections.
The VSLs for Requirement R6 have levels ranked by the failure to inspect a percentage of the
applicable lines to be inspected. To calculate the appropriate VSL the applicable Transmission
Owner or applicable Generator Owner may choose units such as: circuit, pole line, line miles or
kilometers, etc.
For example, when a an applicable Transmission Owner or applicable Generator Owner operates
2,000 miles of applicable transmission lines this applicable Transmission Owner or applicable
Generator Owner will be responsible for inspecting all the 2,000 miles of lines at least once
during the calendar year. If one of the included lines was 100 miles long, and if it was not
inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%.
The “Low VSL” for R6 would apply in this example.
Requirement R7:
R7 is a risk-based requirement. The applicable Transmission Owner or applicable Generator
Owner is required to complete its an annual work plan for vegetation management to accomplish
the purpose of this standard. Modifications to the work plan in response to changing conditions
or to findings from vegetation inspections may be made and documented provided they do not
put the transmission system at risk. The annual work plan requirement is not intended to
necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to
be performed. It is only intended to require that the applicable Transmission Owner or
applicable Generator Owner provide evidence of annual planning and execution of a vegetation
management maintenance approach which successfully prevents encroachment of vegetation into
the MVCD.
For example, when a an applicable Transmission Owner or applicable Generator Owner
identifies 1,000 miles of applicable transmission lines to be completed in the applicable
Transmission Owner’s or applicable Generator Owner’s annual plan, the applicable
Transmission Owner or applicable Generator Owner will be responsible completing those
identified miles. If a applicable Transmission Owner or applicable Generator Owner makes a
modification to the annual plan that does not put the transmission system at risk of an
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
29
FAC-003-23 — Transmission Vegetation Management
encroachment the annual plan may be modified. If 100 miles of the annual plan is deferred until
next year the calculation to determine what percentage was completed for the current year would
be: 1000 – 100 (deferred miles) = 900 modified annual plan, or 900 / 900 = 100% completed
annual miles. If aan applicable Transmission Owner or applicable Generator Owner only
completed 875 of the total 1000 miles with no acceptable documentation for modification of the
annual plan the calculation for failure to complete the annual plan would be: 1000 – 875 = 125
miles failed to complete then, 125 miles (not completed) / 1000 total annual plan miles = 12.5%
failed to complete.
The ability to modify the work plan allows the applicable Transmission Owner or applicable
Generator Owner to change priorities or treatment methodologies during the year as conditions
or situations dictate. For example recent line inspections may identify unanticipated high
priority work, weather conditions (drought) could make herbicide application ineffective during
the plan year, or a major storm could require redirecting local resources away from planned
maintenance. This situation may also include complying with mutual assistance agreements by
moving resources off the applicable Transmission Owner’s or applicable Generator Owner’s
system to work on another system. Any of these examples could result in acceptable deferrals or
additions to the annual work plan provided that they do not put the transmission system at risk of
a vegetation encroachment.
In general, the vegetation management maintenance approach should use the full extent of the
applicable Transmission Owner’s or applicable Generator Owner’s easement, fee simple and
other legal rights allowed. A comprehensive approach that exercises the full extent of legal
rights on the ROW is superior to incremental management because in the long term it reduces the
overall potential for encroachments, and it ensures that future planned work and future planned
inspection cycles are sufficient.
When developing the annual work plan the applicable Transmission Owner or applicable
Generator Owner should allow time for procedural requirements to obtain permits to work on
federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits
may necessitate preparing work plans more than a year prior to work start dates. Applicable
Transmission Owners or applicable Generator Owners may also need to consider those special
landowner requirements as documented in easement instruments.
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be
documented. Depending on the planning and documentation format used by the applicable
Transmission Owner or applicable Generator Owner, evidence of successful annual work plan
execution could consist of signed-off work orders, signed contracts, printouts from work
management systems, spreadsheets of planned versus completed work, timesheets, work
inspection reports, or paid invoices. Other evidence may include photographs, and walk-through
reports.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
30
FAC-003-23 — Transmission Vegetation Management
11
FAC-003 — TABLE 2 — Minimum Vegetation Clearance Distances (MVCD) 11
For Alternating Current Voltages (feet)
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
(kV) 12
MVCD
(feet)
MVCD
(feet)
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
MVCD
feet
Over sea
level up
to 500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over
2000 ft
up to
3000 ft
Over
3000 ft
up to
4000 ft
Over
4000 ft
up to
5000 ft
Over
5000 ft
up to
6000 ft
Over
6000 ft
up to
7000 ft
Over
7000 ft
up to
8000 ft
Over
8000 ft
up to
9000 ft
Over
9000 ft
up to
10000 ft
Over
10000 ft
up to
11000 ft
765
800
8.2ft
8.33ft
8.61ft
8.89ft
9.17ft
9.45ft
9.73ft
10.01ft
10.29ft
10.57ft
10.85ft
11.13ft
500
550
5.15ft
5.25ft
5.45ft
5.66ft
5.86ft
6.07ft
6.28ft
6.49ft
6.7ft
6.92ft
7.13ft
7.35ft
345
362
3.19ft
3.26ft
3.39ft
3.53ft
3.67ft
3.82ft
3.97ft
4.12ft
4.27ft
4.43ft
4.58ft
4.74ft
287
302
3.88ft
3.96ft
4.12ft
4.29ft
4.45ft
4.62ft
4.79ft
4.97ft
5.14ft
5.32ft
5.50ft
5.68ft
230
242
3.03ft
3.09ft
3.22ft
3.36ft
3.49ft
3.63ft
3.78ft
3.92ft
4.07ft
4.22ft
4.37ft
4.53ft
161*
169
2.05ft
2.09ft
2.19ft
2.28ft
2.38ft
2.48ft
2.58ft
2.69ft
2.8ft
2.91ft
3.03ft
3.14ft
138*
145
1.74ft
1.78ft
1.86ft
1.94ft
2.03ft
2.12ft
2.21ft
2.3ft
2.4ft
2.49ft
2.59ft
2.7ft
115*
121
1.44ft
1.47ft
1.54ft
1.61ft
1.68ft
1.75ft
1.83ft
1.91ft
1.99ft
2.07ft
2.16ft
2.25ft
88*
100
1.18ft
1.21ft
1.26ft
1.32ft
1.38ft
1.44ft
1.5ft
1.57ft
1.64ft
1.71ft
1.78ft
1.86ft
72
0.84ft
0.86ft
0.90ft
0.94ft
0.99ft
1.03ft
1.08ft
1.13ft
1.18ft
1.23ft
1.28ft
1.34ft
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014
(refer to the Applicability Section above)
11
The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will
be achieved at time of vegetation maintenance.
12
Where applicable lines are operated at nominal voltages other than those listed, Thethe applicable Transmission Owner or applicable Generator Owner should
use the maximum system voltage to determine the appropriate clearance for that line.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
31
FAC-003-23 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Alternating Current Voltages (meters)
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
MVCD
meters
Over sea
level up
to 152.4
m
Over
152.4 m up
to 304.8 m
Over 304.8
m up to
609.6m
Over
609.6m up
to 914.4m
Over
914.4m up
to
1219.2m
Over
1219.2m
up to
1524m
Over 1524 m
up to 1828.8
m
Over
1828.8m
up to
2133.6m
Over
2133.6m
up to
2438.4m
Over
2438.4m up
to 2743.2m
Over
2743.2m up
to 3048m
Over
3048m up
to
3352.8m
( AC )
Nominal
System
Voltage
(KV)
( AC )
Maximum
System
Voltage
8
(kV)
765
800
2.49m
2.54m
2.62m
2.71m
2.80m
2.88m
2.97m
3.05m
3.14m
3.22m
3.31m
3.39m
500
550
1.57m
1.6m
1.66m
1.73m
1.79m
1.85m
1.91m
1.98m
2.04m
2.11m
2.17m
2.24m
345
362
0.97m
0.99m
1.03m
1.08m
1.12m
1.16m
1.21m
1.26m
1.30m
1.35m
1.40m
1.44m
287
302
1.18m
0.88m
1.26m
1.31m
1.36m
1.41m
1.46m
1.51m
1.57m
1.62m
1.68m
1.73m
230
242
0.92m
0.94m
0.98m
1.02m
1.06m
1.11m
1.15m
1.19m
1.24m
1.29m
1.33m
1.38m
161*
169
0.62m
0.64m
0.67m
0.69m
0.73m
0.76m
0.79m
0.82m
0.85m
0.89m
0.92m
0.96m
138*
145
0.53m
0.54m
0.57m
0.59m
0.62m
0.65m
0.67m
0.70m
0.73m
0.76m
0.79m
0.82m
115*
121
0.44m
0.45m
0.47m
0.49m
0.51m
0.53m
0.56m
0.58m
0.61m
0.63m
0.66m
0.69m
88*
100
0.36m
0.37m
0.38m
0.40m
0.42m
0.44m
0.46m
0.48m
0.50m
0.52m
0.54m
0.57m
72
0.26m
0.26m
0.27m
0.29m
0.30m
0.31m
0.33m
0.34m
0.36m
0.37m
0.39m
0.41m
69*
∗
Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above)
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
32
FAC-003-23 — Transmission Vegetation Management
TABLE 2 (CONT) — Minimum Vegetation Clearance Distances (MVCD)7
For Direct Current Voltages feet (meters)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
±750
±600
±500
±400
±250
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
( DC )
Nominal
Pole to
Ground
Voltage
(kV)
Over sea
level up to
500 ft
Over 500
ft up to
1000 ft
Over 1000
ft up to
2000 ft
Over 2000
ft up to
3000 ft
Over 3000
ft up to
4000 ft
Over 4000
ft up to
5000 ft
Over 5000
ft up to
6000 ft
Over 6000
ft up to
7000 ft
Over 7000
ft up to
8000 ft
Over 8000
ft up to
9000 ft
Over 9000
ft up to
10000 ft
Over 10000
ft up to
11000 ft
(Over sea
level up to
152.4 m)
(Over
152.4 m
up to
304.8 m
(Over
304.8 m
up to
609.6m)
(Over
609.6m up
to 914.4m
(Over
914.4m up
to
1219.2m
(Over
1219.2m
up to
1524m
(Over
1524 m up
to 1828.8
m)
(Over
1828.8m
up to
2133.6m)
(Over
2133.6m
up to
2438.4m)
(Over
2438.4m
up to
2743.2m)
(Over
2743.2m
up to
3048m)
(Over
3048m up
to
3352.8m)
14.12ft
(4.30m)
10.23ft
(3.12m)
8.03ft
(2.45m)
6.07ft
(1.85m)
3.50ft
(1.07m)
14.31ft
(4.36m)
10.39ft
(3.17m)
8.16ft
(2.49m)
6.18ft
(1.88m)
3.57ft
(1.09m)
14.70ft
(4.48m)
10.74ft
(3.26m)
8.44ft
(2.57m)
6.41ft
(1.95m)
3.72ft
(1.13m)
15.07ft
(4.59m)
11.04ft
(3.36m)
8.71ft
(2.65m)
6.63ft
(2.02m)
3.87ft
(1.18m)
15.45ft
(4.71m)
11.35ft
(3.46m)
8.99ft
(2.74m)
6.86ft
(2.09m)
4.02ft
(1.23m)
15.82ft
(4.82m)
11.66ft
(3.55m)
9.25ft
(2.82m)
7.09ft
(2.16m)
4.18ft
(1.27m)
16.2ft
(4.94m)
11.98ft
(3.65m)
9.55ft
(2.91m)
7.33ft
(2.23m)
4.34ft
(1.32m)
16.55ft
(5.04m)
12.3ft
(3.75m)
9.82ft
(2.99m)
7.56ft
(2.30m)
4.5ft
(1.37m)
16.91ft
(5.15m)
12.62ft
(3.85m)
10.1ft
(3.08m)
7.80ft
(2.38m)
4.66ft
(1.42m)
17.27ft
(5.26m)
12.92ft
(3.94m)
10.38ft
(3.16m)
8.03ft
(2.45m)
4.83ft
(1.47m)
17.62ft
(5.37m)
13.24ft
(4.04m)
10.65ft
(3.25m)
8.27ft
(2.52m)
5.00ft
(1.52m)
17.97ft
(5.48m)
13.54ft
(4.13m)
10.92ft
(3.33m)
8.51ft
(2.59m)
5.17ft
(1.58m)
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
33
FAC-003-23 — Transmission Vegetation Management
Notes:
The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a
misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a
technically justified method. The explanation of why the Gallet approach is more appropriate is
explained in the paragraphs below.
The drafting team sought a method of establishing minimum clearance distances that uses
realistic weather conditions and realistic maximum transient over-voltages factors for in-service
transmission lines.
The SDT considered several factors when looking at changes to the minimum vegetation to
conductor distances in FAC-003-1:
• avoid the problem associated with referring to tables in another standard (IEEE-5162003)
• transmission lines operate in non-laboratory environments (wet conditions)
• transient over-voltage factors are lower for in-service transmission lines than for
inadvertently re-energized transmission lines with trapped charges.
FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in
IEEE 516-2003 to determine the minimum distance between a transmission line conductor and
vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task
Force in 1968 from test data provided by thirteen independent laboratories. The distances
provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap,
or in other words, dry laboratory conditions. Consequently, the validity of using these distances
in an outside environment application has been questioned.
FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the
minimum clearance distances. Table 7 could be used if the Transmission Owner knew the
maximum transient over-voltage factor for its system. Otherwise, Table 5 would have to be
used. Table 5 represented minimum air insulation distances under the worst possible case for
transient over-voltage factors. These worst case transient over-voltage factors were as follows:
3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for
765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for
concern in this particular application of the distances.
In general, the worst case transient over-voltages occur on a transmission line that is
inadvertently re-energized immediately after the line is de-energized and a trapped charge is still
present. The intent of FAC-003 is to keep a transmission line that is in service from becoming
de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation.
Thus, the worst case transient overvoltage assumptions are not appropriate for this application.
Rather, the appropriate over voltage values are those that occur only while the line is energized.
Typical values of transient over-voltages of in-service lines, as such, are not readily available in
the literature because they are negligible compared with the maximums. A conservative value
for the maximum transient over-voltage that can occur anywhere along the length of an in-
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
34
FAC-003-23 — Transmission Vegetation Management
service ac line is approximately 2.0 per unit. This value is a conservative estimate of the
transient over-voltage that is created at the point of application (e.g. a substation) by switching a
capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where
capacitor banks are not very common (e.g. Maximum System Voltage of 362 kV), the maximum
transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines
and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.
Even though these transient over-voltages will not be experienced at locations remote from the
bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines
are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor
of 2.0 per unit for transmission lines operated at 302 kV and below is considered to be a realistic
maximum in this application. Likewise, for ac transmission lines operated at Maximum System
Voltages of 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a
realistic maximum.
The Gallet Equations are an accepted method for insulation coordination in tower design. These
equations are used for computing the required strike distances for proper transmission line
insulation coordination. They were developed for both wet and dry applications and can be used
with any value of transient over-voltage factor. The Gallet Equation also can take into account
various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines
in North America.
If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with
the critical spark-over distances computed using the Gallet wet equations, for each of the
nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a
more conservative (larger) minimum distance value.
Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are
not vastly different when the same transient overvoltage factors are used; the “wet” equations
will consistently produce slightly larger distances than the IEEE 516 equations when the same
transient overvoltage is used. While the IEEE 516 equations were only developed for dry
conditions the Gallet equations have provisions to calculate spark-over distances for both wet
and dry conditions.
While EPRI is currently trying to establish empirical data for spark-over distances to live
vegetation, there are no spark-over formulas currently derived expressly for vegetation to
conductor minimum distances. Therefore the SDT chose a proven method that has been used in
other EHV applications. The Gallet equations relevance to wet conditions and the selection of a
Transient Overvoltage Factor that is consistent with the absence of trapped charges on an inservice transmission line make this methodology a better choice.
The following table is an example of the comparison of distances derived from IEEE 516 and the
Gallet equations.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
35
FAC-003-23 — Transmission Vegetation Management
Comparison of spark-over distances computed using Gallet wet equations vs.
IEEE 516-2003 MAID distances
Table 7
(Table D.5 for feet)
( AC )
( AC )
Nom System
Max System
Transient
Over-voltage
Clearance (ft.)
Voltage (kV)
Voltage (kV)
Factor (T)
765
800
2.0
14.36
13.95
500
550
2.4
11.0
10.07
345
362
3.0
8.55
7.47
230
115
242
121
3.0
3.0
5.28
2.46
4.2
2.1
Gallet (wet)
@ Alt. 3000 feet
IEEE 516-2003
MAID (ft)
@ Alt. 3000 feet
Rationale:
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Applicability (section 4.2.4):
The areas excluded in 4.2.4 were excluded based on comments from industry for reasons
summarized as follows: 1) There is a very low risk from vegetation in this area. Based on an
informal survey, no TOs reported such an event. 2) Substations, switchyards, and stations have
many inspection and maintenance activities that are necessary for reliability. Those existing
process manage the threat. As such, the formal steps in this standard are not well suited for this
environment. 3) NERC has a project in place to address at a later date the applicability of this
standard to Generation Owners. 4) Specifically addressing the areas where the standard does
and does not apply makes the standard clearer.
Rationale for R1 and R2:
Lines with the highest significance to reliability are covered in R1; all other lines are covered in
R2.
Rationale for the types of failure to manage vegetation which are listed in order of increasing
degrees of severity in non-compliant performance as it relates to a failure of a Transmission
Owner's vegetation maintenance program:
1. This management failure is found by routine inspection or Fault event investigation, and is
normally symptomatic of unusual conditions in an otherwise sound program.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
36
FAC-003-23 — Transmission Vegetation Management
2. This management failure occurs when the height and location of a side tree within the ROW
is not adequately addressed by the program.
3. This management failure occurs when side growth is not adequately addressed and may be
indicative of an unsound program.
4. This management failure is usually indicative of a program that is not addressing the most
fundamental dynamic of vegetation management, (i.e. a grow-in under the line). If this type of
failure is pervasive on multiple lines, it provides a mechanism for a Cascade.
Rationale for R3:
The documentation provides a basis for evaluating the competency of the Transmission
Owner’s vegetation program. There may be many acceptable approaches to maintain
clearances. Any approach must demonstrate that the Transmission Owner avoids vegetationto-wire conflicts under all Ratings and all Rated Electrical Operating Conditions. See Figure 1 for
an illustration of possible conductor locations.
Rationale for R4:
This is to ensure expeditious communication between the Transmission Owner and the control
center when a critical situation is confirmed.
Rationale for R5:
Legal actions and other events may occur which result in constraints that prevent the
Transmission Owner from performing planned vegetation maintenance work.
In cases where the transmission line is put at potential risk due to constraints, the intent is for
the Transmission Owner to put interim measures in place, rather than do nothing.
The corrective action process is not intended to address situations where a planned work
methodology cannot be performed but an alternate work methodology can be used.
Rationale for R6:
Inspections are used by Transmission Owners to assess the condition of the entire ROW. The
information from the assessment can be used to determine risk, determine future work and
evaluate recently-completed work. This requirement sets a minimum Vegetation Inspection
frequency of once per calendar year but with no more than 18 months between inspections on
the same ROW. Based upon average growth rates across North America and on common utility
practice, this minimum frequency is reasonable. Transmission Owners should consider local and
environmental factors that could warrant more frequent inspections.
Rationale for R7:
This requirement sets the expectation that the work identified in the annual work plan will be
completed as planned. It allows modifications to the planned work for changing conditions,
taking into consideration anticipated growth of vegetation and all other environmental factors,
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
37
FAC-003-23 — Transmission Vegetation Management
provided that those modifications do not put the transmission system at risk of a vegetation
encroachment.
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
38
FAC-003-23 — Transmission Vegetation Management
Version History
Version
1
Date
TBA
Action
1. Added “Standard Development
Roadmap.”
Change Tracking
01/20/06
2. Changed “60” to “Sixty” in section A,
5.2.
3. Added “Proposed Effective Date:
April 7, 2006” to footer.
4. Added “Draft 3: November 17,
2005” to footer.
1
2
April 4, 2007
November 3,
2011
Regulatory Approval - Effective Date
Adopted by the NERC Board of Trustees
Adopted by the Board of Trustees: November 3, 2011Draft 4: April 23, 2012
New
39
Implementation Plan for FAC-003-3 —
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC Glossary of Terms upon approval of FAC-003-3, or the above
definition of Minimum Vegetation Clearance Distance will replace (and thus force the retirement, at
midnight the day before FAC-003-3 is approved) of the same definition in FAC-003-2, if FAC-003-2 has
been approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on the order in which regulatory authorities approve FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming). Once a complete
inventory is created, the Generator Owner will begin the process of gathering information for the
TVMP. In instances where the generation interconnection Facilities are owned by a partnership, a
majority or operating partner will need to obtain partnership approval to proceed with procurement of
Implementation Plan for FAC-003-3
2
a TVMP expert, and later a tree trimming crew. Typically, a request for proposal to hire a TVMP
consultant is initiated which could take several weeks in order to obtain sufficient bids (and also satisfy
Sarbanes Oxley requirements). Once all bids have been received, a contract with a TVMP consultant is
signed. At this point, the TVMP consultant and Generator Owner staff will develop the TVMP, which
needs to take into account local growth conditions, types of vegetation and other aspects required by
FAC-003. Once the TVMP is developed, Generator Owner staff and the TVMP consultant will need to
perform a Right-of-Way inspection (as required in FAC-003-3 Requirement 1), usually done using GPS,
LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-0033 Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation. On an ongoing basis, in
addition to performing inspections and clearances as required by the entity's TVMP, the Generator
Owner will need to ensure that the training and qualification requirements for the standard are met.
The entity will also need to maintain documentation of all FAC-003-3 activities for compliance period of
one year to meet compliance with the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
year after the date of the order approving the standard from applicable regulatory authorities
Implementation Plan for FAC-003-3
3
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees’ adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees’ adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
Implementation Plan for FAC-003-3
4
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
5
Implementation Plan for FAC-003-3 —
Transmission Vegetation Management
Prerequisite Approvals
There are a number of scenarios that could occur regarding the approval of FAC-003-2 that would
affect the implementation of FAC-003-3.
If FAC-003-2 is filed with applicable regulatory authorities and approved before FAC-003-3 is filed with
applicable regulatory authorities, then when and if FAC-003-3 is approved by applicable regulatory
authorities, the implementation plan and effective dates for Transmission Owners in FAC-003-2 will be
transferred into this implementation plan. The “clock” for calculating effective dates for Transmission
Owners will still have started at the time specified in FAC-003-2 (based on the approval date of that
standard). Generator Owners will be required to comply with the implementation plan as outlined
below.
If applicable regulatory authorities elect to approve only FAC-003-3 and not FAC-003-2, the original
implementation plan for Transmission Owners as outlined in FAC-003-2 will be transferred into this
implementation plan. Generator Owners will be required to comply with the implementation plan as
outlined below. The “clocks” for calculating the effective dates for both Transmission Owners and
Generator Owners will begin at the same time.
If applicable regulatory authorities approve FAC-003-2 and FAC-003-3 at the same time, the
implementation plan and effective dates for Transmission Owners in FAC-003-2 will be transferred into
this implementation plan and FAC-003-2 will be immediately retired. Generator Owners will be
required to comply with the implementation plan as outlined below. The “clocks” for calculating the
effective dates for both Transmission Owners and Generator Owners will begin at the same time.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. All
requirements and the two revised definitions in the proposed standard FAC-003-2 will be retired at
midnight the day before FAC-003-3 becomes effective.
There are two revised definitions in the proposed standard:
Right-of-Way (ROW)
The corridor of land under a transmission line(s) needed to operate the line(s). The width of the
corridor is established by engineering or construction standards as documented in either
construction documents, pre-2007 vegetation maintenance records, or by the blowout
standard in effect when the line was built. The ROW width in no case exceeds the applicable
Transmission Owner’s or applicable Generator Owner’s legal rights but may be less based on
the aforementioned criteria.
Vegetation Inspection
The systematic examination of vegetation conditions on a Right-of-Way and those vegetation
conditions under the Transmission Owner’s or applicable Generator Owner’s control that are
likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This
may be combined with a general line inspection.
There is one new definition in the proposed standard:
Minimum Vegetation Clearance Distance (MVCD)
The calculated minimum distance stated in feet (meters) to prevent flash-over between
conductors and vegetation, for various altitudes and operating voltages.
The current glossary definitions of Right-of-Way and Vegetation Inspection, or the glossary definitions
of Right-of-Way and Vegetation Inspection in FAC-003-2, if that standard has been approved, will be
retired at midnight the day before FAC-003-3 (and with it, the above definitions of Right-of-Way and
Vegetation Inspection) becomes effective. The above definition of Minimum Vegetation Clearance
Distance will be added to the NERC glossary Glossary of Terms upon approval of FAC-003-3, or the
above definition of Minimum Vegetation Clearance Distance will replace (and thus force the
retirement, at midnight the day before FAC-003-3 is approved) of the same definition in FAC-003-2, if
FAC-003-2 has been approved.
Compliance with Standard
As outlined above under “Prerequisite Approvals,” the inclusion of Transmission Owners in this
implementation plan will depend on the order in which regulatory authorities approved FAC-003-2 and
FAC-003-3. Therefore, this implementation plan only identifies a compliance timeframe for Generator
Owners to which this standard will apply.
To reach compliance with the standard, a Generator Owner will have to perform a full review of asbuilt drawings and determine which generation interconnection Facilities require a Transmission
Vegetation Management Plan (TVMP) and inspection as specified by NERC Reliability Standard FAC003-3. In general, Generator Owners do not have staff that are qualified and experienced to create a
TVMP, perform Right-of-Way inspections, and perform any required tree trimming (as is required by
FAC-003-3 Requirement 1.3). Once a complete inventory is created, the Generator Owner will begin
the process of gathering information for the TVMP. In instances where the generation interconnection
Facilities are owned by a partnership, a majority or operating partner will need to obtain partnership
Implementation Plan for FAC-003-3
2
approval to proceed with procurement of a TVMP expert, and later a tree trimming crew. Typically, a
request for proposal to hire a TVMP consultant is initiated which could take several weeks in order to
obtain sufficient bids (and also satisfy Sarbanes Oxley requirements). Once all bids have been received,
a contract with a TVMP consultant is signed. At this point, the TVMP consultant and Generator Owner
staff will develop the TVMP, which needs to take into account local growth conditions, types of
vegetation and other aspects required by FAC-003. Once the TVMP is developed, Generator Owner
staff and the TVMP consultant will need to perform a Right-of-Way inspection (as required in FAC-0033 Requirement 1), usually done using GPS, LIDAR and other tools by experienced and qualified staff.
Once a Right-of-Way inspection is completed and clearances are required, the Generator Owner will
need to issue a request for proposal to hire a tree trimming crew that is qualified and experienced to
perform required clearance trimming. Once all bids have been received, a contract with a tree
trimming crew is signed. When the tree trimming crew is acquired, the crew will need to familiarize
themselves with the entity's TVMP and required clearances. The Generator Owner will typically need
to schedule any required outages in order for the tree trimming crew to perform the needed clearance
trimming. This action would also include the implementation of the work plan as required in FAC-003-3
Requirement 2. During scheduled outages, if required, the tree trimming crew will perform any
required clearances and document the activities.
Another typical action is the Generator Owner establishing a system for maintaining TVMP-related
activities, including maintenance of inspection and clearance documentation (as required in FAC-003-3
Requirement 1.2). On an ongoing basis, in addition to performing inspections and clearances as
required by the entity's TVMP, the Generator Owner will need to ensure that the training and
qualification requirements for the standard are met. The entity will also need to maintain
documentation of all FAC-003-3 activities for compliance period of one year to meet compliance with
the standard.
Again, due to a typical lack of experience and qualifications required by FAC-003-3, compliance with
this standard by a Generator Owner may take as long as two years – in part because many entities will
have generator interconnection Facilities in various parts of the country which may require several
instances of TVMP and numerous Right-of-Way inspections.
Effective Date
There are two effective dates associated with this implementation plan:
The first effective date allows Generator Owners time to develop documented maintenance strategies
or procedures or processes or specifications as outlined in Requirement R3.
In those jurisdictions where regulatory approval is required, Requirement R3 applied to the
Generator Owner becomes effective on the first calendar day of the first calendar quarter one
Implementation Plan for FAC-003-3
3
year after the date of the order approving the standard from applicable regulatory authorities
where such explicit approval for all requirements is required. In those jurisdictions where no
regulatory approval is required, Requirement R3 becomes effective on the first day of the first
calendar quarter one year following Board of Trustees’ adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The second effective date allows entities time to comply with Requirements R1, R2, R4, R5, R6, and R7.
In those jurisdictions where regulatory approval is required, Requirements R1, R2, R4, R5, R6,
and R7 applied to the Generator Owner become effective on the first calendar day of the first
calendar quarter two years after the date of the order approving the standard from applicable
regulatory authorities where such explicit approval for all requirements is required. In those
jurisdictions where no regulatory approval is required, Requirements R1, R2, R4, R5, R6, and R7
become effective on the first day of the first calendar quarter two years following Board of
Trustees’ adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Effective dates for individual lines when they undergo specific transition cases:
1. A line operated below 200kV, designated by the Planning Coordinator as an element of an
Interconnection Reliability Operating Limit (IROL) or designated by the Western Electricity
Coordinating Council (WECC) as an element of a Major WECC Transfer Path, becomes subject to
this standard the latter of: 1) 12 months after the date the Planning Coordinator or WECC
initially designates the line as being an element of an IROL or an element of a Major WECC
Transfer Path, or 2) January 1 of the planning year when the line is forecast to become an
element of an IROL or an element of a Major WECC Transfer Path.
2. A line operated below 200 kV currently subject to this standard as a designated element of an
IROL or a Major WECC Transfer Path which has a specified date for the removal of such
designation will no longer be subject to this standard effective on that specified date.
3. A line operated at 200 kV or above, currently subject to this standard which is a designated
element of an IROL or a Major WECC Transfer Path and which has a specified date for the
removal of such designation will be subject to Requirement R2 and no longer be subject to
Requirement R1 effective on that specified date.
4. An existing transmission line operated at 200kV or higher which is newly acquired by an asset
owner and which was not previously subject to this standard becomes subject to this standard
12 months after the acquisition date.
Implementation Plan for FAC-003-3
4
5. An existing transmission line operated below 200kV which is newly acquired by an asset owner
and which was not previously subject to this standard becomes subject to this standard 12
months after the acquisition date of the line if at the time of acquisition the line is designated
by the Planning Coordinator as an element of an IROL or by WECC as an element of a Major
WECC Transfer Path.
Implementation Plan for FAC-003-3
5
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07 (FAC-003-3 and FAC-003-x)
The Generator Requirements at the Transmission Interface Drafting Team thanks all commenters who
submitted comments on the second formal posting of FAC-003-3 and FAC-003-X, as part of Project
2010-07—Generator Requirements at the Transmission Interface. These standards were posted for a
30-day public comment period from March 9, 2012 through April 9, 2012. Stakeholders were asked to
provide feedback on the standards and associated documents through a special electronic comment
form. There were 22 sets of comments, including comments from approximately 83 different people
from approximately 76 companies representing 9 of the 10 Industry Segments as shown in the table on
the following pages.
The SDT considered all comments submitted and has proposed the following minor changes to FAC003-X and FAC-003-3:
•
•
FAC-003-X:
The Applicability section was reformatted to make it clear that the standard applies on a
Facility by Facility basis (as in FAC-003-3), not simply to all generator interconnection
Facilities owned by a Generator Owner with at least one qualifying generator
interconnection Facility.
In the Purpose section, Right-of-Way was capitalized because it is an approved NERC
glossary term and “North American Electric Reliability Council” was changed to “North
American Electric Reliability Corporation.”
Regional Entity was added back to the Applicability section of the standard. Requirement
R4 is assigned to the Regional Entity, and the Project 2010-07 does not have the
authority, based on the scope outlined in its SAR, to modify that requirement. Thus,
Regional Entity must remain in the Applicability section. In all cases, Regional Entity has
been spelled out rather than referred to as “RE.”
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
FAC-003-3:
A typo was found in the Severe VSL for R2; the previous reference to “Transmission
Owner” was changed to “responsible entity,” as in all other FAC-003-3 VSLs.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan.
Other minority comments are addressed alongside their specific comments below.
Note that if both FAC-003-X and FAC-003-3 are approved in this recirculation ballot, only FAC-003-3 will
be presented to NERC’s Board of Trustees. FAC-003-X has been modified so that the generator
interconnection Facility gap can be quickly addressed in the event that neither FAC-003-2 nor FAC-003-3
is approved by FERC.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_Rev%201_20110825.pdf.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
2
Index to Questions, Comments, and Responses
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder
comments submitted in the first successive ballot between October 5 and November 18, 2011,
along with advice from NERC staff. The SDT continues to believe that a reference to line of sight is
clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the line of sight
reference but made a few additional changes for formatting clarity and language consistency. The
team also added a footnote to further explain what it means by “line of sight.” Do you agree with
these changes? If not, please provide specific alternative language. …. ........................................... 8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Michael R. Lombardi Northeast Utilities
NPCC 1
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Don Jones
Group
2
3
4
5
6
7
Texas Reliability Entity
Texas Reliability Entity
ERCOT 10
2. David Penney
Texas Reliability Entity
ERCOT 10
3.
Group
Southwest Power Pool Standards
Development Team
Jonathan Hayes
Additional Member Additional Organization
Region
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
X
X
X
X
X
Segment Selection
1.
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Curtis Crews
8
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Charles
Sheppard
1
2. Rebecca
Berdahl
3
5.
Group
Mike Garton
NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
5, 6
2. Michael Crowley
Electric Transmission
SERC
1, 3
3. Jeff Bailey
Nuclear
MRO
5
4. Sean Iseminger
F&H
SERC
5
5. Chip Humphrey
F&H
NPCC 5
6.
Group
WILL SMITH
MRO NSRF
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL(NSP)
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTLESON
OTP
MRO
1, 3, 4, 5
14. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
15. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
16. THERESA ALLARD
MPC
MRO
1, 3, 5, 6
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7.
Individual
Antonio Grayson
Southern Company
X
8.
9.
Individual
Individual
Brenda Frazer
John Bee
Edison Mission Marketing & Trading
Exelon
X
X
10.
Individual
Ray Phillips
Alabama Municipal Electric Authority
11.
Individual
Joe Petaski
Manitoba Hydro
12.
Individual
Dan Roethemeyer
Dynegy
13.
Individual
Thad Ness
American Electric Power
X
X
X
X
14.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
15.
Individual
Dale Fredrickson
Wisconsin Electric
16.
Individual
Daniel Duff
Liberty Electric Power LLC
17.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
X
18.
Individual
Brian Murphy
NextEra Energy, Inc.
X
19.
Individual
Jean Nitz
ACES Power Marketing
20.
Individual
Patrick Brown
Essential Power, LLC
21.
Individual
Russell A. Noble
Cowlitz County PUD
22.
Individual
Michelle R. D'Antuono
Ingleside Cogeneration LP
X
X
X
X
X
X
X
X
X
7
X
X
X
X
X
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
X
X
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
1.
The Project 2010-07 SDT considered Exelon’s appeal in the context of other stakeholder comments submitted in the first
successive ballot between October 5 and November 18, 2011, along with advice from NERC staff. The SDT continues to
believe that a reference to line of sight is clarifying and makes explicit the SDT’s implicit intent from day one. Thus, it kept the
line of sight reference but made a few additional changes for formatting clarity and language consistency. The team also
added a footnote to further explain what it means by “line of sight.” Do you agree with these changes? If not, please provide
specific alternative language.
Summary Consideration:
Some commenters still do not support the qualifying language for Generator Owners (GOs) or believe that the qualifying
language should be worded differently. The SDT continues to believe that the qualifying criteria for GOs are appropriate;
it has explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant
stakeholder comments, including many possible language options, and is satisfied that it has determined the appropriate
language to address the reliability gap.
Some commenters suggested changes to items – including the content of the VSLs and the tables attached to the
standard that were outside the scope of the SDT’s work.
Some commenters raised questions about the language differences between FAC-003-X and FAC-003-3 and expressed
concern that the language in FAC-003-X could lead to a “null” result whereby the qualifying language is not applied
according to the SDT’s intent. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the language in
4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written, now that it has been reformatted to better match the formatting in FAC-003-3.
Some commenters questioned whether “clear line of sight” means from a fixed point or from any point along the line.
The SDT clarified that it intends for the phrase “from the generating station switchyard fence to the point of
interconnection” to mean that there is a clear line of sight from any point along that length of line.
One commenter questioned whether the standard applies to all generator interconnection Facilities that a GO owns if it
applies to one of them. The SDT clarified that it intended for the standard to apply on a line by line basis in both FAC-003X and FAC-003-3. To clarify this, it has reformatted the Applicability section of FAC-003-X to better match the formatting
in FAC-003-3.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
8
One commenter asked whether the standard applies to the entirety of an applicable generator interconnection Facility,
or just the portion of the line greater than one mile. The SDT clarified that if a GO owns an applicable line, the GO is
responsible for the entirety of that line. The SDT believes that this is clear in the standards as written.
One commenter expressed concern that the implementation timeframe is too long. The SDT reminded the commenter
that the time frame was based on previous stakeholder comments and the fact that the implementation of Version 0
standards – the transition into which marked the time that TOs needed to begin applying FAC-003 on a mandatory basis –
occurred over more than two years. It is therefore reasonable to assume that GOs, having never had to comply with a
vegetation management standard, be afforded adequate time to do so.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previous
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
The SDT considered all comments received and decided to address typos, improve the formatting of the Applicability
section of FAC-003-X, and update the boilerplate language in the Effective Dates sections of the standards and their
implementations plans. The SDT has proposed no substantive changes to the standards.
Organization
Yes or No
Question 1 Comment
Ameren Services
Negative
(a) There is no technical basis for the one mile length exemption. In fact,
one could argue that a very short line, 300 feet in length, that experienced a
fault from a tree at "the end of the circuit", i.e near the switchyard fence,
would have much more of an impact on the BES because the fault would be
limited by much less impedance.
(b) For the GO that owns several lead lines but only one of the lines is
greater than one mile in length, does this standard apply to all the lead lines
he owns? A response can be affirmative with the current language of the
section 4.2.1. If this is not the intent, it should be clarified.
(c) It is also unclear in this version if a GO that owned one line that was 1.2
miles in length would have to comply for the entire length of said line, or
just 0.2 miles of said line. If the GO is responsible for 1.2 miles, then that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
9
Organization
Yes or No
Question 1 Comment
argues that the first mile is important and consequently there is no basis for
ignoring the first mile on other lines. If the GO is only responsible for 0.2
miles, what is the technical basis to ignore a mile? And would it be the first
mile from the switchyard that is ignored, or is the middle mile, or the last
mile where it connects to the TO? Or could the GO decide? Or could the GO
pick sections of the line that amount to a mile that they can ignore? This
seems like something that should be addressed for compliance.
(d) The 2 year compliance time line is far too long. There is significant
industry evidence that was developed in the drafting of Version 2 that
supports a one year compliance time-line for new lines. This is evidenced in
Version 2. Thus there is no basis for the 2 years
Response: Thank you for your comment. The SDT continues to believe that the qualifying criteria for GOs are appropriate; it has
explained its rationale in depth in the posted Technical Justification Document. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap.
The SDT intended for the standard to apply on a line by line basis in both FAC-003-X and FAC-003-3. To clarify this, it has
reformatted the Applicability section of FAC-003-X to better match the formatting in FAC-003-3.
If a GO owns an applicable line, the GO is responsible for the entirety of that line. The SDT believes that this is clear in the
standards as written.
With respect to the Implementation Plan, the SDT reminds Ameren that the time frame was based on previous stakeholder
comments and the fact that the implementation of Version 0 standards – the transition into which marked the time that TOs
needed to begin applying FAC-003 on a mandatory basis – occurred over more than two years. It is therefore reasonable to
assume that GOs, having never had to comply with a vegetation management standard, be afforded adequate time to do so.
BC Hydro and Power Authority
Negative
“BC Hydro agrees with the revisions to FAC-003-3 and would vote
Affirmative except for the following two items.
One: The FAC-003-2 adopted by the NERC Board of Trustees had a
significant change to what was voted on in Draft 6 in the Table of
Compliance Elements (R1 and R2). In the table on Page 13 of the version
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adopted by the NERC Board of Trustees on November 3, 2011, the VSLs
were changed and the staff proposed violation severity levels were adopted
and the review team recommendations were rejected. Therefore, there is
no Low or Moderate VSLs for these two violations only High and Severe.
This was rejected earlier by a number of utilities including BC Hydro and was
not in the version 6 draft that was voted for on the last ballot. This change
as adopted is a concern as it expects a level of program perfection that
seems unrealistic. It is also at odds with the Rationale for R1 and R2 outlined
on Page 32 of the standard “Guideline and Technical Basis” section which
gives an explanation for the increasing levels of violation severity. Program
failures that were deemed to be “unusual conditions in an otherwise sound
program” or “not adequately addressed by the program” formerly rated as
Lower or Moderate VSL are now rated as High. It also extends the severity
of the violation beyond what is currently in FAC-003-1 although the levels of
non-compliance are not strictly comparable between versions. This change
is carried on in the Draft FAC-003-3.
Two: Table 2 (pg. 30 and 31 of FAC-003-3 Draft 3) for Minimum Vegetation
Clearance Distances for AC Voltages now includes clearance calculations for
287 kV which is good and was something BC Hydro asked for. However, the
calculations don’t seem to be correct as the limits are higher than for
345kV. BC Hydro recommends either providing an explanation as to why
these limits seem to be out of sequence to increasing voltage or recalculate
them.”
Response: Thank you for your comment. The SDT's SAR is very limited in scope (determining which additional standards should
apply to a GO/GOP). The SDT made no changes to the VSLs and simply included the FAC-003-2 VSLs that were approved by
NERC’s BOT, as those are the VSLs that will be filed with FERC. Similarly, the SDT made no changes to Table 2, as that would also
have been outside its scope; the SDT exclusively made changes that would add GOs or GOPs to standard requirements or
applicability sections, and changes that would bring the standard up to date according to current NERC templates. No change
made.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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ComEd
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
PECO Energy
Negative
Please refer to Exelon's comments submitted in the electronic comment
form
Gulf Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Mississippi Power
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Alabama Power Company
Negative
See comments submitted via the electronic comments form by Antonio
Grayson.
Utility Services, Inc.
Negative
The applicability language under Version X is not the same as the language
in Version 3. We do not believe that applicability language in Version X can
ever result in a “True” logical outcome whereas the language in Version 3
can. We understand the intent; however, applying the specific language
using the logical "AND" in the applicability portion of the standard will
always come out with a null result. We suggest the SDT adopt the
applicability language in Version 3 in Version X.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
language in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that it has been reformatted to better match the formatting in FAC-003-3. No
change made.
Xcel Energy, Inc.
Negative
This project is counter-productive to the efforts of the Protection System
Maintenance and Testing Standard Drafting Team that concurrently has
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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PRC-005-2 posted for comment and successive ballot.
Response: Thank you for your comment. The SDT believes this comment was submitted in response to PRC-005 and will address
it with comments received under that standard.
SERC Reliability Corporation
Negative
We have concern that if this passes there will be BES Elements that will not
be covered by the vegetation management standard that are currently
included in the standards and that this determiniation is based solely on
ownership and not risk to reliability. SERC supports BES reliability and as
veggetation management was identified as a significant contributor to the
2003 Blackout we do not support a revision that would create a gap in the
results-based, defense-in-depth approach that has been determined to be
necesary for the reliable operation of the interconnected transmission
network.
Response: Thank you for your comment. GOs are not currently covered under any vegetation management requirements, so the
SDT does not understand the comment about removing coverage for BES Elements “that are currently included in standards.”
The applicability to TOs, the entity currently subject to vegetation management requirements, is not changing. The SDT
recognizes that in many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2) the
overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for exempting these Facilities
because incorporating them into FAC-003 would offer no reliability benefit. No stakeholder has commented that there are
similarly situated transmission facilities.
Southern Company
No
The requirement as worded implies or could be interpreted to mean one's
line of site would have to originate at the generating station switchyard
fence. The "clear line of site" should also include that from a roadway that
travels in proximity to the line. Such a roadway's purpose would likely
include access to the line for inspections, maintenance, travel from the
plant to the transmission subsation, etc. Since the terrain between the
generating station switchyard fence and the point of interconnection could
obsure the view from the fence, the clear line of site from such a roadway
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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should be allowed. The requirement should be revised to read, "...or (2)
does not have clear line of sight1 from the generating station switchyard
fence or a roadway to the point of interconnection with a Transmission
Owner's Facility."
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. The SDT has considered all relevant stakeholder
comments and is satisfied that it has determined the appropriate language to address the reliability gap. No change made.
Southwest Power Pool Standards
Development Team
No
Clear line of sight” means the distance that can be seen by the average
person “standing at ground level “without special instrumentation (e.g.,
binoculars, telescope, spyglasses, etc.) on a clear day.
Response: Thank you for your comment. The SDT has considered all relevant stakeholder comments and is satisfied that we
have determined the appropriate language to address the reliability gap.
Cowlitz County PUD
No
Cowlitz must agree with Exelon’s position insomuch that the vantage point
must be related to the generating station switchyard maintenance or the
operation and maintenance of the generation plant itself, and afford a clear
perspective of vegetation proximity. Cowlitz also agrees with the SDT’s line
of sight clarifying verbiage. However, restricting the vantage point to the
generating station switchyard fence does not encompass the spirit of the
exclusion. A short one-mile transmission interconnection line - from the
generating station switchyard to the interconnection point - that is
frequently viewed during the operation and maintenance of the generation
plant itself should be the crux of the exemption.
The exact location, i.e., the generating station switchyard fence, of the
vantage point is not the make or break of whether the interconnection line
will be routinely inspected by default. As an example, consider a hydro
project where the generating station switchyard may be located near the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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tailrace inside a canyon. From the fence line of this particular switchyard,
only the interconnection line traversing up the canyon wall is visible.
However, topside of the dam where maintenance and operational
personnel must daily traverse under the interconnection line to access the
powerhouse and switchyard may afford a clear view of both the generating
station switchyard below and the interconnection station which includes
the whole interconnecting line in-between.
Further, if parts of the interconnecting line is viewable in two or even three
vantage points beneath the interconnection line during the normal transit
to and from the generating station switchyard, the sum of which comprises
the whole line, can this not also meet the spirit of the exclusion?
Conversely, Cowlitz does not hold that any vantage point should be
acceptable. Any vantage point that must require special effort to access no
matter the ease is not acceptable. Also, a perpendicular view of a line (not
under or near) complicates perception of the proximity of vegetation to a
line. Views parallel down the right-of-way maximizes perception of
vegetation proximity.
Further, a long line that is fully viewable during transit to and from the
generation plant increases the chance of hidden vegetation encroachment.
Cowlitz strongly opposes any trivializing of reliability compliance collateral
damage. Forcing compliance activities with no reliability return must be
avoided wherever possible. As a stakeholder with limited time to invest
reviewing all the comments submitted, Cowlitz offers an apology to Exelon
for missing their initial comment. Cowlitz commends Exelon’s persistence in
this matter.
***Suggested language: ...or (2) do not have a clear line of sight (leave the
footnote in place) up and/or down from a single vantage point within the
transmission right-of-way where both the origin at the generating station
switchyard and the termination interconnection point with the Transmission
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Owner’s Facility can be seen, and where operations or maintenance
personnel frequent on foot during normal generation plant or generating
station switchyard access is made...
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to
mean that there is a clear line of sight from any point along that length of line. We do not believe that adding the language you
suggest necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has considered all
relevant stakeholder comments and is satisfied that we have determined the appropriate language to address the reliability
gap. No change made.
Exelon
No
Exelon disagrees with the current proposed draft of FAC-003-3/X because
the reference to a “clear line of sight from the generating station switchyard
fence to the point of interconnection” does not clarify the Standard and is
unsupported by any technical basis. Furthermore, the definition of “clear
line of sight” added by the SDT does not address or remedy the substantive
concerns raised in Exelon’s appeal.
Exelon reiterates that the SDT should base the applicability of the Standard
on the length of the transmission line, a measurable component of the bulk
electric system, and remove all references to a “clear line of sight.” This
approach is consistent with previous draft versions of FAC-003 proposed by
the SDT and the Ad Hoc Group and the recent recommendation of the NERC
Vice President of Standards and Training in response to Exelon’s appeal.
Alternatively, if the “clear line of sight” verbiage remains, the Standards
should be clarified to remove the requirement that the line of sight be
established from “the generating station switchyard fence to the point of
interconnection” and to add a requirement or clarify that “clear line of
sight” for lines of one mile or less can include observation of the length of
the transmission lines from various vantage points within the owner
controlled property. The SDT states in the “Background” section of the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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Unofficial Comment Form that “a reference to the line of sight is clarifying
and makes explicit the SDT’s implicit intent from day one.”
Yet, the SDT offers no support for its “implicit intent from day one,” and a
review of the history for these Standards certainly does not support an
“implicit intent from day one” to require a clear line of sight from a fixed
location, let alone the generating station switchyard fence, to the point of
interconnection. The Technical Justification document posted in September
2011 (p. 3) refers to the Ad Hoc Group’s original thought to exclude from
the Standards any transmission lines that were “less than two spans [long]
(generally one half mile from the generator property line).” In agreeing
“with that intended exclusion in principle,” the SDT explained (p. 3) that,
“[a]fter reviewing formal comments, the SDT agreed to revise the exclusion
so that it applies to a Facility [transmission line] if its length is ‘one mile or
1.609 kilometers beyond the fenced area of the generating station
switchyard’ to approximate line of sign [sic] from a fixed point,” (the fixed
point being the fenced area of the generating station switchyard). From the
start, the Ad Hoc Group and SDT focused on the length of the transmission
line (either a half mile as proposed by the Ad Hoc Group or a mile as
proposed by the SDT) as the proxy for line of sight, the presumption being
that up to a certain distance, the overhead line is in the line of sight at
various locations throughout the Generator Owner’s property and
reasonably subject to being managed through normal day-to-day plant
activities.
The SDT has not, until the most recent iteration of the Standards, focused
on requiring a “clear line of sight from the generating station switchyard
fence to the point of interconnection.” As support for adding the “clear line
of sight” requirement to the FAC-003-3/X Standards in December 2011, the
SDT noted as follows: “We believe that the one mile length is a reasonable
approximation of line of sight, and that using a fixed starting point (at the
fenced area of the generation station switchyard) eliminates confusion and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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any discretion on the part of a Generator Owner or an auditor.” With the
addition of an explicit line of sight reference here, the SDT believes it has
clarified its original intent. (Side bar comments to FAC-003-3, Section 4.3.1
(December 1, 2011); FAC-003-X, Section 4.3.1 (December 1, 2011)).
This explanation does nothing more than (1) reiterate the point the SDT has
maintained throughout the entire drafting process, namely that “the one
mile length” of a transmission line “is a reasonable approximation of line of
sight,” and (2) explain that the SDT included a “fixed starting point” (the
fenced area of the generation station switchyard) from which to measure
the length of the transmission line to address stakeholder concerns about
excessive Generator Owner discretion with respect to the location from
which to take a measurement and inconsistent application of the Standards.
Again, the SDT’s “intent” (implicit or otherwise) “from day one” has nothing
to do with establishing a “clear line of sight from the generating switchyard
fence to the point of interconnection.” In addition, requiring a “clear line of
sight from the generating station switchyard fence to the point of
interconnection” is technically unsupported. The SDT just added the
requirement for a “clear line of sight to the point of interconnection”
language without considering the implications of why such a change was
required or reasonable. While a specific fixed starting point (the generating
station switchyard fence) and end point (the point of interconnection) may
make sense for establishing a starting and ending point from which to
measure the length of the transmission line (the one-mile limitation), it does
not make sense when considering a clear line of sight, especially in light of
stakeholder comments and the SDT’s repeated acknowledgment that in
many cases, generation Facilities are either (1) staffed and the overhead
portion is within the line of sight or (2) the overhead Facility is over a paved
surface. Stakeholders have generally supported the rationale exempting
these Facilities because incorporating them into FAC-003 would offer no
reliability benefit. The SDT and industry comments support the position that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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these qualifiers represent a reasonable and appropriate risk prevention
approach.(Consideration of Comments, Generator Requirements at the
Transmission Interface, Project 2010-07 (for November 9, 2011 successive
ballot), p. 1; Technical Justification Resource Document (posted March
2012), p. 3.)
By inserting the “clear line of sight” requirement now without modifying the
fixed starting point, the SDT completely ignores its unequivocal
acknowledgment that generation Facilities are unique in the sense that
personnel can see the line from various locations within the owner
controlled area and many generation Facilities are over paved surfaces. The
absence of a technical justification for imposing a “clear line of sight” is
illustrated by the following example.
A Generator Owner transmission line leaving the generating station could
take a “dog leg” turn (the line turns at one of the towers). Standing at the
tower in this example, an individual would have a clear line of sight of the
entire line to either end of the short-distance line (to the end leaving the
station and to the end terminating at the point of interconnection). Since
the generating Facility is within the Generator Owner’s property line or
controlled area and consistently staffed by personnel who patrol the owner
controlled area, the line can be observed and maintained by staff in the
same manner as any other short distance line with a “clear” line of sight
from the “generating station switchyard fence to the point of
interconnection.” Moreover, to the extent a portion or the entire length of
the line travels over paved surfaces or structures, any barriers or obstacles
to a clear line of sight will not be caused by vegetation, as discussed in FAC003-3/X but, rather, by equipment, components, or structures. Clearance
between generator lines and structures is already covered in other NERC
Standards. For those lines that do travel over areas of vegetation, the
regular personnel monitoring and surveillance of the areas over which the
lines travel provides reasonable assurance of protection from vegetation
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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related events.
Rather than clarifying the Standards, the SDT has introduced more
ambiguity into the Standards. The addition of the “generating station
switchyard fence” as the point of reference for a clear line of sight adds
more confusion than it solves by introducing a variable that will be left to
the discretion of generator owner and an auditor. What is the definition of
a “generating station switchyard fence?” As Exelon noted in its Appeal and
at least one other Registered Entity noted in its Comments for the first
successive ballot (Consideration of Comments posted March 2012, p. 38),
some generation facilities do not have generating switchyards or generating
switchyard fences. A requirement that there be a clear line of sight from the
“generating switchyard fence” is meaningless in cases where no such
switchyard or fence exists. Is it the fence surrounding the generating unit or
is it meant to refer to the fence surrounding the Transmission Owner’s
associated switchyard and relay house? What if there are multiple physical
fence lines between the generating unit and the point of interconnection?
In addition, by introducing a point of reference that is not a physical
component or measurable reference of the bulk electric system, what
precludes the Generator Owner from arbitrarily moving the fence line to
avoid applicability? Also lacking in clarity is the addition of a footnote
defining “clear line of sight” to mean “the distance that can be seen by the
average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.” Generation Owners will be left to
determine what constitutes an “average person,” a “clear day,” and “special
instrumentation.”
For all these reasons, Exelon requests that the SDT base the applicability of
the Standard on the length of the transmission line, a measurable
component of the bulk electric system, and remove all references to a
“clear line of sight.” Alternatively, if the “clear line of sight” verbiage
remains, the Standards should be clarified to remove the requirement that
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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the line of sight be established from “the generating station switchyard
fence to the point of interconnection” and to add a requirement or clarify
that “clear line of sight” for lines of one mile or less can include observation
of the length of the transmission lines from various vantage points within
the owner controlled property.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt.
The SDT intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that
there is a clear line of sight from any point along that length of line. We do not believe that adding a reference to a fixed
vantage point necessarily adds clarity, and we’re concerned that it may raise additional questions. In sum, the SDT has
considered all relevant stakeholder comments and is satisfied that we have determined the appropriate language to address
the reliability gap. No change made.
Texas Reliability Entity
No
In FAC-003-X:
1. We appreciate that you took Regional Entity out of the Applicability
section, but there is still a Requirement (R4) that applies to the Regional
Entity. Is that Requirement intended to be enforceable against the Regional
Entities? We suggest removing Requirement R4.
2. In Part D.1.1, only the Regional Entity should be listed as Compliance
Monitor, since the Regional Entity has been removed as an Applicable
entity.
3. In the Purpose section, update the reference to NERC (use “Corporation”
instead of “Council”), and capitalize “Rights-of-Way” since it is a defined
term.
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4. We suggest that you spell out “Regional Entity” in Applicability part 4.2.1.
5. In the implementation plan, the reference to “R3” should be corrected to
“R1” in the following sentence: “In those jurisdictions where no regulatory
approval is required, Requirement R3 becomes effective on the first day of
the first calendar quarter one year following Board of Trustees adoption.”
In FAC-003-3:
6. There is no Compliance Monitor listed on page 17. At least the Regional
Entity should be listed here.
7. In the Severe VSL for R2, replace “Transmission Owner” with
“responsible entity.”
8. In the Severe VSL for R1 and R2, remove “active transmission line” before
“ROW.” That phrase is confusing in the VSLs because it does not appear in
the requirements, and it is not clear whether it is intended to change the
requirements.
9. In Table 2 (Alternating Current - meters AND Direct Current) the footnote
references are wrong. We think they should be 9 and 10, rather than 7 and
8.
10. In Table 2 (Direct Current), the column headings are wrong. Only the
first column heading should refer to voltage. The rest should refer to
MVCD.
Response: Thank you for your comment.
1. The SDT has reverted back to the original Applicability (which included the Regional Entity) because deleting a requirement
is outside the scope of this drafting team.
2. Because the Regional Entity was returned to the Applicability section, the second bullet in section D1.1 must remain.
3. Changes made.
4. Regional Entity has been spelled out in all cases.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
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5.
6.
7.
8.
Change made.
The Compliance Enforcement Authority section has been updated as suggested.
Change made.
Modifying the VSLs beyond the change from “Transmission Owner” to “responsible entity” is not within the scope of the
SDT, and these VSLs have already been approved by NERC’s BOT.
9. These are 9 and 10 in both the clean version and the redline version.
10. The Project 2010-07 SDT did not modify this table.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project
2010-07. If a Generator Owner is required to register as a TO, all the
Requirements applicable to a TO should apply. There is no need to change
specific Reliability Standards to allow the Generator Owner to perform only
selected TO functions.For additional information, please see Manitoba
Hydro's comments submitted in the comment period ending November 18,
2011. Manitoba Hydro does not believe that the SDT fully addressed our
concerns in their responses to our comments in that commenting period.
Response: Thank you for your comment. Under the SDT’s changes, GOs are not going to be required to register as TOs, so this
comment does not apply.
To reiterate our comments in previous comment reports, the intent of the SDT’s SAR is to address all reliability gaps associated
with ownership or operation of an interconnection Facility by a generation entity (GO/GOP). The SDT determined that it should
first address “low-hanging fruit” and believes these to be sole-use Facilities (see posted examples under “Supporting Materials”
posted alongside the December ballot) – that is, a Facility used to connect one or more generators to a Facility owned or
operated by a transmission entity (TO/TOP). Through our deliberations, we came to the conclusion that an interconnection
Facility owned or operated by a GO or GOP that is more complex would likely require specific analysis and that such analysis
would most likely be outside the scope of this SDT.
The SDT also refers the commenter to the document titled Project 2010-07: Generator Requirements at the Transmission
Interface Background Resource Document.
Liberty Electric Power LLC
No
The "line of sight" should be removed. It opens up the entity to a finding of
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non-compliance if a temporary blockage of line of sight should occur.
Response: Thank you for your comment. We maintain that the addition of the reference to “clear line of sight” is clarifying and
helps support the rationale behind the one mile exemption. A line less than one mile that passes through a dense grove should
not be exempt from this standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over
a paved surface should be exempt. Nothing in the proposed standard prohibits an entity from self-imposing the requirements
contained within in order to mitigate any perceived risk of potential non-compliance. No change made.
Northeast Power Coordinating
Council
No
The Applicability language used in FAC-003-X is different from that used in
FAC-003-3. The language used in FAC-003-X uses “and” in several places
which leads to confusion and a probable “null” result, whereas the language
in FAC-003-3 is more straightforward and makes use of “or”. The FAC-003-3
applicability language should be used in FAC-003-X.The explanation of what
is meant by line of sight should be incorporated in the Applicability Section
wording as standards, at NERC’s direction, are supposed to be getting away
from the use of footnotes.
Response: Thank you for your comment. The SDT sought to keep the language of 4.3.1 of FAC-003-X consistent with the
formatting in 4.2.1 of FAC-003-X. The SDT does not believe the language in Version X can lead to a “null” result; we believe the
language is as clear as possible as written now that the formatting has been updated to better reflect the formatting in FAC-0033. No change made.
NextEra Energy, Inc.
No
Under the line of sight approach, a generation lead would be exempt from
the requirements of FAC-003-3 if personnel can see the generation lead
corridor and the generation lead is less than a mile. The rationale provided
to support of this proposal is that “Stakeholders have generally supported
the rationale for exempting these Facilities because incorporating them into
FAC-003 would offer no reliability benefit.”
However, there is no data that supports that generation leads of less than a
mile are categorically not subject to vegetation contacts and outages.
Further, in practice this approach will unduly discriminate against longer
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Question 1 Comment
generator leads, many of which are associated with renewable energy
resource, such as wind and solar.
NextEra Energy Inc. (NextEra) believes a more technically sound approach is
that all generator leads be subject to FAC-003-3, with the opportunity to be
exempted from FAC-003-3 regulation upon an affirmative demonstration
that no vegetation threat exists.
To implement this approach, NextEra proposes that FAC-003-3 applicability
4.3.1 be revised to read as follows: “Overhead transmission lines, including
generation leads, beyond the fenced area of the generating station
switchyard to the point of interconnection with a Transmission Owner and
are:4.3.1.1. Operated at 200kV or higher; or 4.3.1.2. Operated below 200kV
identified as an element of an IROL under NERC Standard FAC-014 by the
Planning Coordinator; or. 4.3.1.3. Operated below 200 kV identified as an
element of a Major WECC Transfer Path in the Bulk Electric System by
WECC.”
NextEra would also propose to add a new section 4.3.2 that reads as
follows:”If a Generator Owner or Transmission Owner can demonstrate that
the entire Right-of-Way is paved or otherwise devoid of vegetation, and
reasonably expected to remain so, the Generation Owner or Transmission
Owner is exempt from FAC-003-3.”
In addition, NextEra proposes that the drafting team consider a megawatt
(MW) threshold for a generating plant from both a stand-alone and
aggregate bases. For example, it is unlikely that vegetation contact tripping
a 50 megawatt generator (or a generator of 100 MWs in the aggregate)
connected to a robust transmission system with a large amount of load and
generation will adversely impact reliability.
Thus, NextEra proposes the addition of a provision that exempts a
generation lead for stand-alone generators of 50 MWs and below and
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
25
Organization
Yes or No
Question 1 Comment
generators in the aggregate of 100 MWs and below, unless there is an
affirmative request for the generator to comply with FAC-003-3 by a
Transmission Operator or Reliability Coordinator. Such a provision could
read as follows:”Unless a Transmission Operator or Reliability Coordinator
requests in writing that a stand-alone generator of 50 Megawatts (MWs) or
below (with a 200 kV or above generation lead) or a generator in the
aggregate of 100 MWs or below (with a 200 kV or above generation lead)
comply with FAC-003-3, these classes of generators and their associated
generation leads are exempt from complying with FAC-003-3. In the event a
Transmission Operator or Reliability Coordinator requests in writing that a
stand-alone generator of 50 Megawatts (MWs) or below (with a 200 kV or
above generation lead) or a generator in the aggregate of 100 MWs or
below (with a 200 kV or above generation lead) comply with FAC-003-3, the
associated registered entity shall have one-year from the date of the written
correspondence to come into compliance with FAC-003-3.”
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. And because there are many GOs whose lines would fall into these categories, the SDT believes the exemption is
necessary and prevents GOs with little to no reliability risk from incurring undue cost and compliance risk in the development
and maintenance of a vegetation management plan. In sum, the SDT has considered all relevant stakeholder comments and is
satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Dynegy
No
Using the switchyard fence is to restrictive. There could be to many
different layouts to keep it fair for all GO's. For example, there could be an
obstruction if limited to standing at the existing switchyard fence but if one
were to move a short distance away (i.e. corner of GO's building) then it
could be possible to see both ends of the tie line. This would also meet the
intent of the added language since it is now within line of sight. I
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
26
Organization
Yes or No
Question 1 Comment
recommend deleting "switchyard fence". Also, in order to account for a GO
not being able to dictate what happens inside a TO's switchyard, I
recommend adding "entry or" between "of" and "interconnection".
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and believes that using the fixed starting point of the
switchyard fence is best for eliminating confusion and any discretion on the part of a Generator Owner or an auditor. The SDT
intends for the phrase “from the generating station switchyard fence to the point of interconnection” to mean that there is a
clear line of sight from any point along that length of line. In sum, the SDT has considered all relevant stakeholder comments
and is satisfied that we have determined the appropriate language to address the reliability gap. No change made.
Wisconsin Electric; Wisconsin
Electric Power Co.; Wisconsin
Electric Power Marketing; Wisconsin
Energy Corp.
No
We strongly oppose the addition of the “clear” line of sight criteria to the
Applicability. The report of the GOTO Task Force, as well as prior draft
revisions to FAC-003, included a test based solely on circuit length, which is
sufficient in our view to assure that the BES is not at risk due to vegetation
issues on generator tie lines. The expansion to include short tie lines,
including those entirely on the Generator Owner’s property which may not
meet the line of sight qualifier, has no benefit to reliability. Rather, the
expanded applicability and the requirement for a formal vegetation
management program in these cases will consume resources for compliance
that are better used for actual reliability improvements.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. We maintain that the addition of the reference to “clear line of sight” is clarifying and helps support the rationale
behind the one mile exemption. A line less than one mile that passes through a dense grove should not be exempt from this
standard, but a line that is less than one mile and is either (1) staffed and within line of sight or (2) over a paved surface should
be exempt. The SDT has considered all relevant stakeholder comments and is satisfied that we have determined the
appropriate language to address the reliability gap. No change made.
ExxonMobil Research and
Engineering
No
While it is clear that the SDT is attempting to include those facilities owned
by Generator Owners that travel long distances down right-of-ways, the
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
27
Organization
Yes or No
Question 1 Comment
applicability section of FAC-003-X and FAC-003-3, as written, require
industrial complexes with cogeneration facilities to develop Transmission
Vegetation Management Programs for generator lead lines that are not
exposed to vegetation.
Industrial cogeneration location is typically chosen based on the availability
of fuel, need for steam, or availability of real estate. This can result with the
generation facilities (including the GSU transformer substation) being
located deep within the plant with long cable routes and multiple substation
connections between the GSU transformer substation and utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. Additionally, the routes of these generator lead lines
fundamentally differ in nature from a typical IPP’s generator lead line route.
Since they are located within the fence line of an industrial complex, the
routes rarely contain vegetation; are frequently travelled by plant
personnel; rarely run in straight lines (i.e. no single line of sight); and
frequently terminate at a facility located at the fence line of the industrial
complex where a transmission company takes ownership of the power lines
that leave the industrial complex. Furthermore, the use of the term
“generating station switchyard” may result in inconsistent enforcement of
the Transmission Vegetation Management Program Reliability Standard as
the use of the term implies there is only one substation located within a
Generator Owner’s complex. Typically, there are multiple substations that
connect an industrial complex’s generator lead-line to the utility
interconnection facility located near the perimeter of the industrial
complex’s fence line. The two obvious interpretations for the “generating
station switchyard” are the substation that is directly connected to the
generator’s GSU, and the utility interconnection facility. The concerns
raised by NERC and FERC staff related generator owned transmission like
assets originate with those conductors that leave the Generator Owner’s
complex’s fence line and travel long distances down vacant right-of-ways,
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
28
Organization
Yes or No
Question 1 Comment
and, therefore, the applicability of those Reliability Standards that apply to
transmission facilities should start with the fence line.
Since the Bulk Electric System is contiguous, reliability concerns related to
the facilities between the GSU transformer substation and utility
interconnection facility are covered by those Reliability Standards that apply
to Generator Owners and Generator Operators. In order to account for the
different nature of industrial complex’s generation facilities, the SDT should
consider re-phrasing the applicability section of FAC-003-X and FAC-003-3 to
start counting the length of a generator lead line at the fence line of the
Generator Owner’s complex and not the generating station switchyard.
Response: Thank you for your comment. The SDT appreciates this discussion, and had many similar discussions during its own
deliberations. The SDT considered many options for a starting point, and for language in general within this qualifier, and it
believes that using the fixed starting point of the switchyard fence is best for eliminating confusion and any discretion on the
part of a Generator Owner or an auditor. In sum, the SDT has considered all relevant stakeholder comments and is satisfied that
we have determined the appropriate language to address the reliability gap, while exempting the most common lines with little
to no reliability risk for a vegetation issue. No change made.
City of Bartow, Florida; City of
Clewiston; Florida Municipal Power
Agency; Beaches Energy Services
Affirmative
Although we are supporting the change, the added applicability language
for GOs is ambiguous as to whether the qualifier "operated at 200 kV and
above and any lower voltage lines designated by the Regional Entity as
critical to the reliability of the electric system in the region" applies to both
portions of the applicability (e.g., 1) > 1 mile and 2) no clear line of sight), or
just to the second no clear line of sight applicability. FMPA assumes that the
qualifier applies to both. We recommend re-arranging of the sentence to
make this clearer by moving the qualifier to the beginning of the sentence
instead of the end of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the qualifier language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with 4.1.1 of FAC-003-X. No change
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
29
Organization
Yes or No
Question 1 Comment
Affirmative
AWEA supports the modifications in this standard, along with the other
standards modification under Project 2010-07, as a reasonable approach to
addressing the perceived reliability concerns with generator tie lines. We
believe a consistent approach for all Generator Owners and Generator
Operators that does not require registration as a Transmission Owner or
Transmission Operator is the most efficient and effective way to address
these concerns.
made.
American Wind Energy Association
Response: The SDT thanks you for your comment and support.
BrightSource Energy, Inc.
Affirmative
BrightSource would like to thank the SDT for the effort in developing the
standard. Our comment is more on providing more clarification. Depending
on the agreements between the TO and the GO, the Point of
Interconnection is not necessarily the point of change of ownership of the
transmission facilities. For example, the GO may own the portion of the
Gen-tie from the generating plant to the last tower outside the TO’s
substation and the TO owns the line drop from the last tower to the
termination equipment inside the TO substation. So to avoid confusion later
we suggest that we modify P4.3.1 by adding “to the point of change of
ownership or” as follows: “4.3.1. Generator Owner that owns an overhead
transmission line(s) that (1) extends greater than one mile or 1.609
kilometers beyond the fenced area of the generating station switchyard to
the point of change of ownership or to the point of interconnection with a
Transmission Owner’s Facility or (2) does not have a clear line of sight1 from
the generating station switchyard fence to the point of interconnection with
a Transmission Owner’s Facility and is operated at 200 kV and above and
any lower voltage lines designated by the Regional Entity as critical to the
reliability of the electric system in the region.” Thank you.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
30
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comment and support. The SDT considered many different language choices for its
qualifying language, and it believes that “point of interconnection” is a clear phrase that will be understood and appropriately
applied. No change made.
Indiana Municipal Power Agency
Affirmative
IMPA supports the change, but would add the comment that the added
applicability language for GOs is ambiguous as to whether the qualifier
"operated at 200 kV and above and any lower voltage lines designated by
the Regional Entity as critical to the reliability of the electric system in the
region" applies to both portions of the applicability which are 1) > 1 mile
and 2) no clear line of sight), or just to the second portion for no clear line of
sight applicability. IMPA assumes that the qualifier applies to both. We
recommend reorganizing the sentence to make this more clear by moving
the qualifier to the beginning of the sentence.
Response: Thank you for your comment. The SDT agrees that the qualifier applies to both (1) and (2) in the exemption language
and used that language formatting to keep the formatting of 4.2.1 of FAC-003-X consistent with the formatting in 4.1.1 of FAC003-X. No change made.
Nebraska Public Power District
Affirmative
NPPD joins the comments submitted by the MRO NSRF (Midwest Reliability
Organization - NERC Standards Review Forum)
Midwest Reliability Organization
Affirmative
Please refer to comments made by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review
Forum.
Lakeland Electric
Affirmative
See FMPA comments
Great River Energy
Affirmative
See NSRF comments
Bonneville Power Administration
Yes
BPA has no other comments or concerns at this time.
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
31
Organization
NERC Compliance Policy
Yes or No
Yes
Question 1 Comment
Dominion offers the following comments on the Implementation Plan for
FAC-003-3:
1. The last paragraph on page 2 refers to FAC-003-3 Requirement 1.3. FAC003-3 does not appear to contain a Requirement 1.3; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
2. The 3rd paragraph on page 3 refers to FAC-003-3 Requirement 1.2. FAC003-3 does not appear to contain a Requirement 1.2; therefore, Dominion
recommends that the reference in the Implementation Plan be clarified.
Response: Thank you for these suggestions. These references have been removed.
MRO NSRF
Yes
The NSRF agrees with the clarifying changes related to adding the phrase
“.....do not have a clear line of sight from the generating station switchyard
fence to the point of interconnection with a Transmission Owner’s
Facility.......”, however, have the following comment for SDT consideration:
o The Evidence Retention in FAC-003-3, Part C, Compliance, and
Section1.2implies that an entity is required to retain evidence for the time
period since the last audit. Since Generator Owners’ audit cycles are six (6)
years, and the following paragraph statesthat to show compliance for R1,
R2, R3, R5, R6 and R7is three calendar years unless directed by the CEA to
retain longer as part of an investigation, this section should be clarified to
require six years retention for applicable Generator Owners.
Response: Thank you for your comment. The SDT believes the data retention section is appropriate as written. No change made.
Edison Mission Marketing & Trading
Yes
Alabama Municipal Electric
Authority
Yes
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
32
Organization
Yes or No
American Electric Power
Yes
Public Service Enterprise Group
Yes
ACES Power Marketing
Yes
Essential Power, LLC
Yes
Ingleside Cogeneration LP
Yes
Question 1 Comment
END OF REPORT
Consideration of Comments: GOTO Project 2010-07 – FAC-003-3 and FAC-003-x
33
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Entity on request
(within 30 calendar days). The documentation of the program implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
D. Compliance
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
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1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels (no changes)
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
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1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
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Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
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Appendix 2
Requirement Number and Text of Requirement
R1.
Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
Question:
1. Does R1 require a maintenance and testing program for the battery chargers for the “station batteries”
that are considered part of the Protection System?
2. Does R1 require a maintenance and testing program for auxiliary relays and sensing devices? If so,
what types of auxiliary relays and sensing devices? (i.e transformer sudden pressure relays)
3. Does R1 require maintenance and testing of transmission line re-closing relays?
4. Does R1 require a maintenance and testing program for the DC circuitry that is just the circuitry with
relays and devices that control actions on breakers, etc., or does R1 require a program for the entire
circuit from the battery charger to the relays to circuit breakers and all associated wiring?
5. For R1, what are examples of "associated communications systems" that are part of “Protection
Systems” that require a maintenance and testing program?
Response:
1. While battery chargers are vital for ensuring “station batteries” are available to support Protection
System functions, they are not identified within the definition of “Protection Systems.” Therefore,
PRC-005-1 does not require maintenance and testing of battery chargers.
2. The existing definition of “Protection System” does not include auxiliary relays; therefore,
maintenance and testing of such devices is not explicitly required. Maintenance and testing of such
devices is addressed to the degree that an entity’s maintenance and testing program for 3 DC control
circuits involves maintenance and testing of imbedded auxiliary relays. Maintenance and testing of
devices that respond to quantities other than electrical quantities (for example, sudden pressure
relays) are not included within Requirement R1.
3. No. “Protective Relays” refer to devices that detect and take action for abnormal conditions.
Automatic restoration of transmission lines is not a “protective” function.
4. PRC-005-1 requires that entities 1) address DC control circuitry within their program, 2) have a basis
for the way they address this item, and 3) execute the program. PRC-005-1 does not establish specific
additional requirements relative to the scope and/or methods included within the program.
5. “Associated communication systems” refer to communication systems used to convey essential
Protection System tripping logic, sometimes referred to as pilot relaying or teleprotection. Examples
include the following:
•
communications equipment involved in power-line-carrier relaying
•
communications equipment involved in various types of permissive protection system
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
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applications
•
direct transfer-trip systems
•
digital communication systems (which would include the protection system communications
functions of standard IEC 618501 as well as various proprietary systems)
Ap ril 23, 2012
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Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
A. Introduction
1.
Title:
Transmission and Generation Protection System Maintenance and Testing
2.
Number:
PRC-005-1.1b
3.
Purpose:
To ensure all transmission and generation Protection Systems affecting the
reliability of the Bulk Electric System (BES) are maintained and tested.
4.
Applicability
4.1. Transmission Owner.
4.2. Generator Owner.
4.3. Distribution Provider that owns a transmission Protection System.
5.
Effective Date:
To be determined
B. Requirements
5.
R1. Effective Date: In those jurisdictions where regulatory approval is required, all
requirements become effective upon approval. In those jurisdictions where no regulatory
approval is required, all requirements become effective upon Board of Trustee’s adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
B. Requirements
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall have a Protection System maintenance and testing program for
Protection Systems that affect the reliability of the BES. The program shall include:
R1.1.
Maintenance and testing intervals and their basis.
R1.2.
Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System shall provide documentation of its Protection System maintenance and
testing program and the implementation of that program to its Regional Reliability
OrganizationEntity on request (within 30 calendar days). The documentation of the program
implementation shall include:
R2.1. Evidence Protection System devices were maintained and tested within the defined
intervals.
R2.2.
Date each Protection System device was last tested/maintained.
C. Measures
M1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have an associated Protection
System maintenance and testing program as defined in Requirement 1.
Page 1 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
M2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation or generator interconnection Facility
Protection System that affects the reliability of the BES, shall have evidence it provided
documentation of its associated Protection System maintenance and testing program and the
implementation of its program as defined in Requirement 2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability OrganizationEntity.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall retain evidence of the implementation of
its Protection System maintenance and testing program for three years.
The Compliance Monitor shall retain any audit data for three years.
1.4. Additional Compliance Information
The Transmission Owner and any Distribution Provider that owns a transmission
Protection System and the Generator Owner that owns a generation or generator
interconnection Facility Protection System, shall each demonstrate compliance through
self-certification or audit (periodic, as part of targeted monitoring or initiated by
complaint or event), as determined by the Compliance Monitor.
2.
Violation Severity Levels of Non-Compliance(no changes)
2.1. Level 1: Documentation of the maintenance and testing program provided was
incomplete as required in R1, but records indicate maintenance and testing did occur
within the identified intervals for the portions of the program that were documented.
2.2. Level 2: Documentation of the maintenance and testing program provided was complete
as required in R1, but records indicate that maintenance and testing did not occur within
the defined intervals.
2.3. Level 3: Documentation of the maintenance and testing program provided was
incomplete, and records indicate implementation of the documented portions of the
maintenance and testing program did not occur within the identified intervals.
2.4. Level 4: Documentation of the maintenance and testing program, or its implementation,
was not provided.
Page 2 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1
February 7,
2006
Adopted by NERC Board of Trustees
1a
November 5,
2009
Interpretation of R1, R1.1, and R1.2
adopted by the NERC Board of Trustees
Project 2009-10
Interpretation
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers adopted by the NERC
Project 2009-17
Interpretationinterpretati
on
Board of Trustees (adopted and filed as 1a instead of -1b)
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
regarding applicability of standard to
protection of radially connected
transformersof R1 and R2 (FERC’s Order
Project 2009-17
Interpretation
is effective as of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order is effective as ofdated
March 14, 2012). Updated version from
1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
Revision under Project
1.1b
Page 3 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
FERC approval of PRC-005-1b.
1.1b
May 9, 2012
2010-07
Adopted by Board of Trustees
Page 4 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Appendix 1
Requirement Number and Text of Requirement
R1. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall have a
Protection System maintenance and testing program for Protection Systems that affect the
reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
R1.2. Summary of maintenance and testing procedures.
R2. Each Transmission Owner and any Distribution Provider that owns a transmission Protection
System and each Generator Owner that owns a generation Protection System shall provide
documentation of its Protection System maintenance and testing program and the
implementation of that program to its Regional Reliability Organization on request (within 30
calendar days). The documentation of the program implementation shall include:
R2.1 Evidence Protection System devices were maintained and tested within the defined intervals.
R2.2 Date each Protection System device was last tested/maintained.
Question:
Is protection for a radially-connected transformer protection system energized from the BES considered a
transmission Protection System subject to this standard?
Response:
The request for interpretation of PRC-005-1 Requirements R1 and R2 focuses on the applicability of the
term “transmission Protection System.” The NERC Glossary of Terms Used in Reliability Standards
contains a definition of “Protection System” but does not contain a definition of transmission Protection
System. In these two standards, use of the phrase transmission Protection System indicates that the
requirements using this phrase are applicable to any Protection System that is installed for the purpose of
detecting faults on transmission elements (lines, buses, transformers, etc.) identified as being included in
the Bulk Electric System (BES) and trips an interrupting device that interrupts current supplied directly
from the BES.
A Protection System for a radially connected transformer energized from the BES would be considered a
transmission Protection System and subject to these standards only if the protection trips an interrupting
device that interrupts current supplied directly from the BES and the transformer is a BES element.
Page 5 of 9
Standard PRC-005-1.1b — Transmission and Generation Protection System Maintenance and
Testing
Page 6 of 9
Implementation Plan for PRC-005-1.1b—
Transmission and Generation Protection
System Maintenance and Testing
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already-approved standards. PRC-005-1b
will be retired when PRC-005-1.1b becomes effective.
Compliance with Standard
The proposed changes to Requirement R1 and R2 are clarifying changes. While there was no reliability
gap in the previous version of the standard, if applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection
System, exclusive of its generator interconnection Facility Protection System. The minor changes to R1
and R2 make clear that generator interconnection Facilities are also part of Generator Owners’
responsibility in the context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
Implementation Plan for PRC-005-1.1a1b—
Transmission and Generation Protection
System Maintenance and Testing
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no proposed revisions to requirements in other already approved standards. PRC-005-1a 1b
will be retired when PRC-005-1.1a 1b becomes effective.
Compliance with Standard
The proposed changes to Requirement R1 and R2 are clarifying changes. While there was no reliability
gap in the previous version of the standard, if applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection
System, exclusive of its generator interconnection Facility Protection System. The errataminor changes
to R1 and R2 make clear that generator interconnection Facilities are also part of Generator Owners’
responsibility in the context of this standard.
Because the change is merely a clarifying change, no additional time for compliance is needed.
Effective Date
In those jurisdictions where regulatory approval is required, all requirements become effective upon
approval. In those jurisdictions where no regulatory approval is required, all requirements become
effective upon Board of Trustees’ adoption or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
Consideration of Comments
Generator Requirements at the Transmission Interface
Project 2010-07: PRC-005-1.1a
The GOTO Drafting Team thanks all commenters who submitted comments on the first formal posting
for PRC-005-1.1a, part of Project 2010-07—Generator Requirements at the Transmission Interface.
Overwhelmingly, commenters approved the standard as written, and the team appreciates that
support. These standards were posted for a 45-day public comment period from March 2, 2012
through April 16, 2012. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 19 sets of comments, including
comments from approximately 65 different people from approximately 38 companies representing 9 of
the 10 Industry Segments as shown in the table on the following pages.
A few commenters did not support the use of the term
“generator interconnection Facility” without a formal
definition. Based on comments received elsewhere in this
project, the SDT has avoided the creation of new NERC
glossary terms, and has received significant industry
support for that strategy. While it is possible that other
language could have been used, the SDT believes the
reference “generator interconnection Facility” is clear.
Note: PRC-005-1b was approved by
FERC on March 14, 2012. Thus, the
changes the SDT proposes will be
applied to that version of the
standard. To reduce confusion, the
SDT’s modified standard is still
referred to as PRC-005-1.1a below,
but all other documents going
forward will be appropriately
updated to reference PRC-005-1.1b
and incorporate the associated
interpretation.
Some commenters are concerned about the changes
proposed in PRC-005-1.1a given the fact that PRC-005-2 is
also being revised. PRC-005-2 does not have the same
issues as PRC-005-1, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of Trustees, the SDT
wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard.
That portion of the standard was modified by NERC staff during the quality review to add boilerplate
compliance language recently approved by NERC legal staff. Modifying it further is outside the scope of
this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing
PRC-005-1a. As noted in the text box above, going forward, all references to PRC-005-1.1a will be
changed to refer to PRC-005-1.1b.
Some commenters stated that the addition of “generator interconnection Facility” was unnecessary
because that Facility is already considered part of the Generator Owner’s assets. While the SDT
believes that Generator Owners do treat the generator interconnection Facility as one of their assets,
commenters in previous postings suggested that adding “generator interconnection Facility” could add
clarity to the specific language in PRC-004 and PRC-005. It was pointed out to the SDT that language in
the requirements of PRC-004 and PRC-005 differed from PRC-001-1, so if the requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only
responsible for analyzing its generator Protection Systems, exclusive of its generator interconnection
Facility Protection Systems under PRC-004 and PRC-005 (whereas this interpretation wasn’t a risk
under PRC-001).
PRC-001-1 used language that had more a more broad application as noted below:
• R1 – “…shall be familiar with the purpose and limitations of protection system schemes applied
in its area.”
• R2 – “…shall notify reliability entities of relay or equipment failures as follows...”
• R3 “…shall coordinate new protective systems and changes as follows…”
PRC-004-2a and PRC-005-1b originally used language which could be construed as being more
restrictive (as shown below):
• PRC-004-2a@R2 – “The Generator Owner shall analyze its generator Protection System
Misoperations...”
• PRC-005-1b@R1 – “…each Generator Owner that owns a generation Protection System…”
• PRC-005-1b@R2 – “…each Generator Owner that owns a generation Protection System…”
The SDT agreed with the comments and modified the standards accordingly.
Other minority comments are addressed alongside their specific comments below.
The SDT considered all stakeholder comments submitted and determined that, save for the update to
reference PRC-005-1.1b instead of PRC-005-1.1a, no additional changes are necessary. The standard
will be posted for a recirculation ballot.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-07_GOTO_Project.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
3
Index to Questions, Comments, and Responses
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection
Facility” in Requirements R1 and R2 of PRC-005-1.1a. While there was no reliability gap in the
previous version of the standard, if the Requirements were applied literally, there was the
possibility for the misperception that the Generator Owner was only responsible for analyzing its
generator Protection Systems, exclusive of its generator interconnection Facility Protection
Systems. The clarifying changes to R1 and R2 make clear that generator interconnection Facilities
are also part of Generator Owners’ responsibility in the context of this standard. Do you support
the addition of the phrase “or generator interconnection Facility” to accomplish this clarification?
…. ......................................................................................................................................................... 9
2.
Do you have any other comments that you have not yet addressed? If yes, please explain. …. .... 13
Consideration of Comments: Project 2010-07 PRC-005-1.1a
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Jesus Sammy Alcaraz
Imperial Irrigation District (IID)
Additional Member Additional Organization Region Segment Selection
1. Jose Landeros
IID
WECC 1, 3, 4, 5, 6
2. Epi Martinez
IID
WECC 1, 3, 4, 5, 6
2.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
X
2
3
X
4
X
5
X
6
X
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
6.
Mike Garton
Dominion Resources Services, Inc.
7.
Kathleen Goodman ISO - New England
NPCC 2
8.
Chantel Haswell
FPL Group, Inc.
NPCC 5
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
NPCC 1
11. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
12. Bruce Metruck
New York Power Authority
NPCC 6
13. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
14. Robert Pellegrini
The United Illuminating Company
NPCC 1
15. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
16. David Ramkalawan Ontario Power Generation, Inc.
NPCC 5
17. Brian Robinson
Utility Services
NPCC 8
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc.
Group
Additional Member Additional Organization
Region
5
6
7
X
X
X
X
X
Segment Selection
1.
Jonathan Hayes
Southwest Power Pool
SPP
NA
2.
Robert Rhodes
Southwest Power Pool
SPP
NA
3.
Dan Lusk
Xcel Energy
SPP
1, 3, 5, 6
4.
Julie Lux
Westar
SPP
1, 3, 5, 6
5.
Mahmood Safi
OPPD
MRO
1, 3, 5
6.
Roy Boyer
Xcel Energy
SPP
1, 3, 5, 6
7.
Mitchell Williams
Western Farmers
SPP
1, 3, 5
8.
John Pasierb
East Texas
NA - Not Applicable NA
9.
David Kral
Xcel Energy
SPP
1, 3, 5, 6
Westar
SPP
1, 3, 5, 6
10. Tom Hesterman
4
3
Southwest Power Pool Standards
Development Team
Jonathan Hayes
3
NPCC 5
10. Michael R. Lombardi Northeast Utilities
3.
2
Consideration of Comments: Project 2010-07 PRC-005-1.1a
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Tiffani Lake
Westar
SPP
6, 1, 3, 5
12. Don Taylor
Westar
SPP
1, 3, 5, 6
4.
Chris Higgins
Group
Bonneville Power Administration
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. Dean
5.
Bender
Group
WECC 1
Mike Garton
Dominion- NERC Compliance Policy
Additional Member Additional Organization Region Segment Selection
1. Connie Lowe
NERC Compliance Policy RFC
6
2. Louis Slade
NERC Compliance Policy SERC
5
3. Michael Crowley
Electric Transmission
SERC
1, 3
4. Sean Iseminger
Fossil & Hydro
SERC
6
5. Chip Humphrey
Fossil & Hydro
NPCC 6
6. Jeff Bailey
Nuclear
MRO
6.
Group
Jean Nitz
Additional Member
6
ACES Power Marketing Standards
Collaborators
Additional Organization
X
Region Segment Selection
1. Mohan Sachdeva
Buckeye Power, Inc
2. Scott Brame
North Carolina Electric Membership Corporation SERC
RFC
1, 3, 4, 5
3. Clem Cassmeyer
Western Farmers Electric Cooperative
1, 5
SPP
7.
Individual
Keira Kazmerski
Xcel Energy
8.
Individual
Dan Roethemeyer
Dynegy Inc.
9.
Individual
John Bee
Exelon
10.
Individual
Art Salander
HindlePower, Inc
11.
Individual
John Seelke
Individual
13. Individual
14.
3, 4
X
X
X
X
X
Public Service Enterprise Group
X
X
X
X
Martin Kaufman
Michelle R D'Antuono
ExxonMobil Research and Engineering
Ingleside Cogeneration LP
X
Individual
Dale Fredrickson
We Energies
15.
Individual
Michael Falvo
Independent Electricity System Operator
16.
Individual
Joe Petaski
Manitoba Hydro
12.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17.
18.
Individual
Individual
19. Individual
Thad Ness
American Electric Power
X
Darryl Curtis
Will Smith
Oncor Electric Delivery Company
MRO NSRF
X
Consideration of Comments: Project 2010-07 PRC-005-1.1a
2
3
X
4
5
X
6
7
X
8
8
9
10
1.
Based on stakeholder comment, the SDT inserted the phrase “or generator interconnection Facility” in Requirements R1 and
R2 of PRC-005-1.1a. While there was no reliability gap in the previous version of the standard, if the Requirements were
applied literally, there was the possibility for the misperception that the Generator Owner was only responsible for analyzing
its generator Protection Systems, exclusive of its generator interconnection Facility Protection Systems. The clarifying
changes to R1 and R2 make clear that generator interconnection Facilities are also part of Generator Owners’ responsibility in
the context of this standard. Do you support the addition of the phrase “or generator interconnection Facility” to accomplish
this clarification?
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Over 90% of commenters
approved the standard as written, and the team appreciates that support.
A few commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility is clear, and no changes were made.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary and complicates the
ongoing development of PRC-005-2. The SDT believes that the clarifying language is necessary, and points out that if PRC005-1.1a proceeds to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because
the drafting team working on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended
March 28, 2012.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and incorporated that language prior to the last posting.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
9
Organization
Southwest Power Pool Standards
Development Team
Yes or No
Question 1 Comment
No
We would advise the Drafting team to take a look at the FERC OATT to
reconcile the term “generator interconnection facility “with Tariff term for
the LGIA. This should clarify the point of delineation and there should be no
misconception of the language as written.
Response: Thank you for the comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new terms. No change made.
Xcel Energy
No
Xcel Energy does not believe that trying to implement a revision of PRC-0051 at this point improves the reliability of the grid. There are better means of
clarifying the perceived “misperceptions” than drafting a standard revision.
This is particularly the case when PRC-005-2 is further along in the process
and is also posted for industry comment and ballot. The effort of the GOTO
SDT is counterproductive.
Response: Thank you for your comment. The SDT revised the standard based upon comments it received suggesting that it do so.
We do agree that there may have been alternative means to address the issue, such as a request for interpretation or CAN, but
given this was in the scope of the SAR, the SDT modified the standard to add the clarity recommended. If PRC-005-1.1a proceeds
to recirculation ballot next as planned, it will actually be slightly ahead of the PRC-005-2 work, because the drafting team working
on PRC-005-2 is still reviewing stakeholder comments from a successive ballot that ended March 28, 2012.
ExxonMobil Research and
Engineering
No
The bulk electric system is contiguous. Therefore, any facility owned by the
Generator Owner that is used to connect the Generator Owner’s generation
facilities to the bulk electric system is already considered a bulk electric
system asset and part of the Generator Owner’s generation facilities. As
stated by in the question above, the addition of the term “or generator
interconnection Facility” does not resolve a reliability gap or add any
substance to the requirement
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
Consideration of Comments: Project 2010-07 PRC-005-1.1a
10
Organization
Yes or No
Question 1 Comment
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Kansas City Power & Light (Note:
Comment was manually added)
No
The phrase “generator interconnection” facility lacks definition making it
difficult to comment on the proposed change. It is important for the
standards and requirements to clearly delineate, define, or identify the
facilities or operating condition subject to application of the standards and
requirements.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation
of new terms. No change made.
Ingleside Cogeneration LP
Yes
Since PRC-005-1 already requires the Generation Owner to maintain and
test all their BES Protection System components, it seems to Ingleside
Cogeneration LP that the need to specify those which may trip the
interconnection facility as redundant. However, we do not believe that the
Standard Development Team’s modifications materially change the intent of
the Standard - nor can they lead an audit team to assign a double violation
for a single incidence of non-compliance.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no
reliability gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the
misperception that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its
generator interconnection Facility Protection Systems. We believe that the clarifying change is useful.
Imperial Irrigation District (IID)
Yes
Northeast Power Coordinating
Council
Yes
Imperial Irrigation District (IID)
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
11
Organization
Yes or No
Bonneville Power Administration
Yes
Dominion- NERC Compliance Policy
Yes
ACES Power Marketing Standards
Collaborators
Yes
Dynegy Inc.
Yes
HindlePower, Inc
Yes
Public Service Enterprise Group
Yes
We Energies
Yes
Independent Electricity System
Operator
Yes
Manitoba Hydro
Yes
American Electric Power
Yes
Oncor Electric Delivery Company
Yes
Consideration of Comments: Project 2010-07 PRC-005-1.1a
Question 1 Comment
12
2.
Do you have any other comments that you have not yet addressed? If yes, please explain.
Summary Consideration:
The SDT thanks all commenters for their feedback on the proposed changes to PRC-005-1.1a. Overwhelmingly,
commenters approved of the standard as written, and the team appreciates that support.
Some commenters are concerned about the changes proposed in PRC-005-1.1a given the fact that PRC-005-2 is also
being revised. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are needed to that
standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s Board of
Trustees, the SDT wants to ensure that the generator interconnection Facility is covered.
Some commenters were concerned about the language in the Data Retention section of the standard. That portion of the
standard was modified by NERC staff during the quality review to add boilerplate compliance language recently approved
by NERC legal staff. Modifying it further is outside the scope of this SDT.
Some commenters pointed out that PRC-005-1b was approved by FERC on March 14, 2012, replacing PRC-005-1a. Going
forward, all references to PRC-005-1.1a will be changed to refer to PRC-005-1.1b.
Some commenters did not support the use of the term “generator interconnection Facility” without a formal definition.
Based on comments received elsewhere in this project, the SDT has avoided the creation of new NERC glossary terms,
and has received significant industry support for that strategy. While it is possible that other language could have been
used, the SDT believes “generator interconnection Facility” is clear, and no changes were made.
One commenter was concerned that the addressing of a literal “reliability gap” should not be considered an errata
change. The SDT maintains that there is no actual reliability gap in the current standard language – just the possible
perception of one. The SDT and most stakeholders still believe that the clarifying change is a useful one, but it is
appropriate to classify as a minor change because it does not change the scope or intent of the associated standard. Still,
the SDT agrees that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to
its changes as errata.
One commenter was concerned that the standard as written does not allow for alternative testing programs in cases
where testing programs do not follow the ownership of the equipment. The SDT points out that an entity can enter into
an agreement (including a Coordinated Functional Registration) whereby another entity is assigned responsibility for
compliance with one or more requirements of one or more reliability standards without the standard itself being so
modified. The SDT therefore does not agree that this standard should be explicitly modified to allow what the commenter
suggests.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
13
One commenter was concerned about the statement that “no changes” were made to the VSLs. Because the SDT has not
proposed changes that affect the scope or intent of the current standard, no changes to the VSLs were necessary. The
same VSLs that have been approved by FERC (which can be found in the VSL matrix posted on NERC’s website:
http://www.nerc.com/page.php?cid=2|20|288) will remain in effect.
One commenter stated that the addition of “generator interconnection Facility” was unnecessary because that Facility is
already considered part of the Generator Owner’s assets. While the SDT believes that Generator Owners do treat the
generator interconnection Facility as one of their assets, some commenters in previous postings suggested that adding
“generator interconnection Facility” could add clarity to the specific language in PRC-004 and PRC-005. The SDT agreed
and modified the standards accordingly.
One commenter continues to find the changes proposed under Project 2010-07 to be unnecessary. As it has in previously
consideration of comment reports, the SDT points out that it must act within the scope of the SAR for this project. As
mandated by its SAR, the SDT has addressed standards for which there is a reliability gap or possible perception of a gap
when it comes to the generator interconnection Facility, as justified in great depth in its Technical Justification document.
One commenter encouraged the SDT to update the Effective Dates and Implementation Dates language to incorporate
the latest NERC legal boilerplate language. That change has been made.
The SDT considered all of these comments and determined that, save for the update to reference PRC-005-1.1b instead
of PRC-005-1.1a, no additional changes are necessary.
Organization
Yes or No
Baltimore Gas & Electric
Company
Southwest Power Pool
Standards Development Team
Abstain
Yes
Question 2 Comment
Please refer to comments submitted by Exelon.
This effort seems to be redundant due to the work going on with PRC-005-2. We do
not understand why this change is being made and it wasn’t made very clear in the
red line changes or in this comment form background.
Response: Thank you for your comment. The Project 2007-17 Protection System Maintenance and Testing SDT is working on
comprehensive changes to PRC-005, as described in detail in the SAR posted on that projects webpage, while the Project 2010-07
Consideration of Comments: Project 2010-07 PRC-005-1.1a
14
Organization
Yes or No
Question 2 Comment
Generator Requirements at the Transmission Interface SDT is focused on making surgical revisions to standards where there might be
a reliability gap related to generator-owned Transmission Facilities. The current draft of PRC-005-2 does not have the same issues as
PRC-005-1 with respect to generator-owned Facilities, so no additional changes are needed to that standard to incorporate generator
interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT, the Project 2010-07 SDT wants to ensure that the
generator interconnection Facility is covered.
Bonneville Power
Administration
Yes
Regarding Section 1.3 Data Retention, BPA believes that it would be difficult for an
entity to provide “other evidence” to demonstrate compliance when the data
retention period is shorter than the time since the last audit. BPA requests the
drafting team to offer guidance as to what "other evidence" could be provided other
than what is already described in the measures. BPA believes that suggesting there
is some “other evidence” without providing a description leaves the TO’s and GO’s
without clear direction on how to comply with the standard. BPA suggests the data
retention period should be three years or since the time the last audit occurred,
whichever is longer for each TO and GO to retain evidence.Should the drafting team
revise the Data Retention language to reflect BPA’s concerns, BPA would vote in
favor of PRC-005-1.1a.
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
ACES Power Marketing
Standards Collaborators
Yes
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Exelon
Yes
The standard language should be clarified to allow for alternative testing programs,
agreed upon by both TO and GO, in cases where testing programs do not follow
ownership of the equipment for all Component Types so long as all of the protection
for the generator interconnection facility is covered.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
15
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. An entity can enter into an agreement (including a Coordinated Functional Registratyion)
whereby another entity is assigned responsibility for compliance with one or more requirements of one or more reliability standards
without the standard itself being so modified. The SDT therefore does not agree that this standard should be explicitly modified to
allow this. No change made.
ExxonMobil Research and
Engineering
Yes
The SDT has utilized two terms in this round of the drafting process whose
definitions are subject to interpretation. The terms ‘generating station switchyard’
and ‘generator interconnection Facility’ need to be defined to prevent inconsistent
enforcement or need for the development of a Compliance Application Notice. As
referenced in our comments to FAC-003-X/3, when you try to apply the term
‘generating station switchyard’ to an industrial complex that contains multiple
substations between the GSU and utility interconnection facility (another substation)
in order to measure the generator lead line for the 1 mile quota, there are several
candidates that appear to fit the criteria.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. While the SDT concedes there may be other language that could be used, the language posted has wide
industry support, therefore no change will be made.
American Electric Power
Yes
While we support changing the standard requirements as proposed, AEP offers the
following comments and suggestions.While the implementation plans states that
“there was no reliability gap in the previous version of the standard”, the previous
version of the standard, if applied literally, does indeed contain a reliability gap in
that it does not require Generation Owners that own a transmission Protection
System to have a Protection System maintenance and testing program. It is AEP’s
understanding that referring to the proposed revision as “PRC-005-1.1a” implies
errata from PRC-005-1a, and the announcement refers to “very limited revisions”. If
there is indeed a gap of responsibility in this standard, any changes to remediate
such a gap would not be errata, regardless of the amount of proposed changes in
content. As such, we recommend that the drafting team use a full revision naming
Consideration of Comments: Project 2010-07 PRC-005-1.1a
16
Organization
Yes or No
Question 2 Comment
convention for these proposed changes, i.e. PRC-005-2.In addition, making these
changes immediately effective would allow no opportunity for an entity to take the
proper steps to become compliant. We believe the revision should include an
implementation plan that allows industry adequate time to analyze their system and
complete any additionally required maintenance and testing activities.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is a useful one, but it is appropriate to classify as a
minor change because it does not change the scope or intent of the associated standard. Regarding the naming convention, the SDT
was advised that the errata naming convention would be acceptable to avoid confusion with the more complete set of revisions to
PRC-005 that are underway in Project 2007-17. The SDT had previously used the word “errata” to describe its changes, but agrees
that the errata label is confusing, as errata changes do not require a ballot. The SDT will no longer refer to its changes as errata. No
change made.
Southern Illinois Power Coop.,
Brazos Electric Power
Cooperative, Inc.
Affirmative
The Implementation Plan for PRC-005-1.1a should be updated to reflect the
retirement of currently effective PRC-005-1b instead of PRC-005-1a. PRC-005-1b
became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. The SDT agrees with the comment and has made the suggested changes.
Pacific Gas and Electric
Company
Affirmative
The data retention period identified in D1.3 cannot be shorter than the time
between audits or the prior maintenance and testing interval
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
AEP Service Corp., AEP and
AEP Marketing, American
Electric Power
Affirmative
Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power
Consideration of Comments: Project 2010-07 PRC-005-1.1a
17
Organization
Yes or No
Question 2 Comment
Great River Energy
Affirmative
Great River Energy agrees with the comments of the MRO NSRF.
Dairyland Power Coop.
Affirmative
Please see comments submitted by MRO NSRF.
Muscatine Power & Water
Affirmative
Please see comments submitted by the MRO NERC Standards Review Forum
Madison Gas and Electric Co.
Affirmative
Please see MRO NSRF comments.
Omaha Public Power District
Affirmative
Please see MRO NSRF Comments.
Brazos Electric Power
Cooperative, Inc.
Affirmative
See ACES Power Marketing comments.
Occidental Chemical
Affirmative
See comments submitted by Ingleside Cogeneration LP
Central Electric Power
Cooperative
Affirmative
See Matt Pacobit's comments from AECI
Southern Company Services,
Inc.
Affirmative
None
Alabama Power Company
Affirmative
None
Georgia Power Company
Affirmative
None
Gulf Power Company
Affirmative
None
Mississippi Power
Affirmative
None
Southern Company
Generation and Energy
Affirmative
None
Consideration of Comments: Project 2010-07 PRC-005-1.1a
18
Organization
Yes or No
Question 2 Comment
Marketing
Beaches Energy Services
Affirmative
Independent Electricity
System Operator
(No Comments.)
The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 of the draft standard and P. 1
of the Implementation Plan, to the following effect:”, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.”
Response: Thank you for your comment. The language you cite has been approved by NERC legal and has been updated in the
Effective Dates section and in the Implementation Plan.
Sunflower Electric Power
Corporation
Negative
A new term is introduced that is not a NERC defined term, the term is generator
interconnection Facility. The term was inserted without comment and clearly is
intended to include something that is not covered by the Standard. This new term
should be removed or defined in Glossary of Terms so entities may understand just
what is covered by this new term. The Implementation Plan for PRC-005-1.1a should
be updated to reflect the retirement of currently effective PRC-005-1b instead of
PRC-005-1a. PRC-005-1b became effective on March 14, 2012 replacing PRC-005-1a.
Response: Thank you for your comment. As recommended by stakeholders throughout this project, the SDT has avoided creation of
new NERC glossary terms. The SDT purposefully did not create a new term (note that only Facility is capitalized, while generator and
interconnection are not). No change made.
Seminole Electric Cooperative,
Inc.
Negative
a) Section D.2 Violation Severity Levels (no changes) - The standard should stand on
its own, therefore, just stating that the VSLs have "(no changes") is incomplete and
will lead to confusion. Please provide definition and clarity to this section.
Response: Thank you for your comment. The SDT has not proposed changes that affect the scope or intent of the current standard,
Consideration of Comments: Project 2010-07 PRC-005-1.1a
19
Organization
Yes or No
Question 2 Comment
and because of that, no changes to the VSLs are necessary. The same VSLs that have been approved by FERC (which can be found in
the VSL matrix posted on NERC’s website: http://www.nerc.com/page.php?cid=2|20|288) will remain in effect. No change made.
Austin Energy, City of Austin
dba Austin Energy
Negative
Adding the words "generator interconnection" to the Facility description does not
add clarity to the Standard. PRC-005-1 is clear as written, indicating the actual owner
of a device supporting the BES is responsible for performing the actions necessary to
comply with PRC-005. The term "generator interconnection" is not defined and
introduces confusion, making responsibility for the application of the Requirements
less clear.
Response: Thank you for your comment. The SDT added the language to add clarity. As we cited above, while there was no reliability
gap in the previous version of the standard, if the Requirements were applied literally, there was the possibility for the misperception
that the Generator Owner was only responsible for analyzing its generator Protection Systems, exclusive of its generator
interconnection Facility Protection Systems. We believe that the clarifying change is useful. No change made.
Kansas City Power & Light Co.
Negative
Concerns have been expressed in the Standard comment forms provided by NERC.
Tucson Electric Power Co.
Negative
It would be difficult for an entity to provide "other evidence" to demonstrate
compliance when the data retention period is shorter than the time since the last
audit. Suggest that the data retention period language should be modified to "three
years or since the time the last audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Thus, it is outside the scope of the SDT and no change was made.
Bonneville Power
Administration
Negative
Please refer to BPA's comments submitted separately.
Manitoba Hydro
Negative
Please see comments submitted by Joe Petaski (Manitoba Hydro)
Xcel Energy, Inc.
Negative
Xcel Energy sees this project as counter-productive to the efforts of the Protection
Consideration of Comments: Project 2010-07 PRC-005-1.1a
20
Organization
Yes or No
Question 2 Comment
System Maintenance and Testing Standard Drafting Team that currently has PRC005-2 posted for comment and successive ballot.
Response: Thank you for your comment. PRC-005-2 does not have the same issues as PRC-005-1, so no additional changes are
needed to that standard to incorporate generator interconnection Facilities, but in case PRC-005-2 does not proceed to NERC’s BOT,
we want to ensure that the generator interconnection Facility is covered.
City and County of San
Francisco
Negative
This revision should be used as an opportunity to clean up language relating to the
data retention period for PRC-005. The following language has been suggested and
appears consistent with the actual data retention period needed for all functional
registrations encompassed by this Standard: "three years or since the time the last
audit occurred, whichever is longer"
Response: Thank you for your comment. This section was revised by NERC staff to add boilerplate compliance language recently
approved by NERC legal staff. Other changes are outside the scope of the SDT.
HindlePower, Inc
No
I beleive that the requirments as shown in 1-4a - c need to be better clarified as to
the actual tasks required. There seems to be no real distinction between Verification
and inspection. There is no clear reporting structure and the requirment to
substitute Ohmic readings vs. discharge test is not basede on any industry reliable
standards. since there is much debate in the industry as to the validity if Ohmic
testing and it has not been accepted by the IEEE as an acceptbale practice I would
rather see terms in line with either IEEE standard or manufacvturer's
recommendations.
Response: Thank you for your comment. The SDT believes these comments may have been intended for the Project 2007-17 drafting
team which is making comprehensive revisions to PRC-005-2. The comment will be forwarded to that team by NERC staff.
Manitoba Hydro
No
Manitoba Hydro does not support the changes being proposed in Project2010-07 in
general. If a Generator Owner is required to register as a TO, all theRequirements
applicable to a TO should apply. There is no need to changespecific Reliability
Consideration of Comments: Project 2010-07 PRC-005-1.1a
21
Organization
Yes or No
Question 2 Comment
Standards to allow the Generator Owner to perform onlyselected TO functions.For
additional information, please see Manitoba Hydro's commentssubmitted in the
comment period ending November 18, 2011. Manitoba Hydrodoes not believe that
the SDT fully addressed our concerns in their responsesto our comments in that
commenting period.
Response: Thank you for your comment. The SDT must act within the scope of the SAR for this project. The comments appear to
indicate that the entity disagrees with the SAR although they cite the Technical Justification document. The Technical Justification
document is meant to be used to show how the SDT arrived at its decisions to revise only 4 reliability standards as opposed to all that
were originally include in the Ad Hoc report, or those in the cited FERC orders.
MRO NSRF
Section D, Article 1.3 Data Retention states that the entities retain evidence for the
entire audit period since the last audit. Furthermore, in the 2nd paragraph of Article
1.3, it states that an entity “shall retail evidence of the implementation of its
Protection System maintenance and testing program for three years.”
If an entity is to prove compliance related to R2.1 and R2.2 of PRC-005-1.1a, the
NSRF recommends that Evidence Retention be revised to state “the two most
recent performance of each distinct maintenance activity for the Protection System
Components, or all performances of each distinct maintenance activity for the
Protection System Component since the previous scheduled audit date, whichever is
longer.”This agrees with the current draft in progress for PRC-005-2 Section D,
Compliance, Article 1.3, paragraph 4.
The NSRF is also concerned with those testing intervals, such as 12 years, which
would dictate a Registered Entity maintain 24 years of records, which is
unreasonable. This should be revised to have documentation for the most current
one testing interval, if after 06/18/07.
The NSRF believes that “the term “generation” in R1 and R2 should be changed to
“generator”. If changed, both Measures will need to be updated as well.
Consideration of Comments: Project 2010-07 PRC-005-1.1a
22
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comment. The Data Retention section was revised by NERC staff to add boilerplate compliance
language approved elsewhere. Thus, it is outside the scope of the SDT and no change was made.
In R1 and R2, the reference to “generation” was in the original standard, referring to a generation Protection System. While
“generator” may work better here, it is not within the scope of the 2010-07 SDT to change language outside the surgical insertion of
“generator interconnection Facility.”
Oncor Electric Delivery
Company
No
Imperial Irrigation District (IID)
No
Northeast Power Coordinating
Council
No
Imperial Irrigation District (IID)
No
Dominion- NERC Compliance
Policy
No
Xcel Energy
No
Dynegy Inc.
No
Public Service Enterprise
Group
No
Ingleside Cogeneration LP
No
Consideration of Comments: Project 2010-07 PRC-005-1.1a
23
Organization
Yes or No
We Energies
No
Question 2 Comment
END OF REPORT
Consideration of Comments: Project 2010-07 PRC-005-1.1a
24
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
The SDT’s technical justification
document has not changed
substantively since it was posted in
December 2011, but the document
below has been updated to reflect
the posted changes to FAC-003-3 and
FAC-003-X.
As part of its work on Project 2010-07—Generator
Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability
standards and 102 requirements to determine what
changes are necessary to close a reliability gap with
respect to what is commonly known as the generator
interconnection Facility. Many of these standards and requirements had been addressed in the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad Hoc
Report) and additional standards were reviewed as a result of informal discussions with NERC and FERC
staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system; and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission; and, thus, require the Generator Owner and Generator Operator for the
Facility to be classified and registered as a Transmission Owner and Transmission Operator, the SDT
does not believe this is necessary to provide an appropriate level of reliability for the BES. Just as
important, such classification and registration could actually cause a reduction in reliability. Generator
Owners and Generator Operators do not need, and in some cases may be prohibited from having, a
wide-area view and responsibility for the integrated transmission system. Requiring Generator Owners
and Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility
Ratings Recommendation to Industry was issued (which included Generator Owners and specifically
addressed interconnection Facilities in the Q&A document with the statement that the alert applied to
generator interconnection tie lines that are radial only and do not serve load “if the generator is
considered part of the bulk electric system”). While this applies to a specific NERC recommendation,
the SDT considers this compelling evidence that the paradigm for thinking about generator
interconnection Facilities is shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004; and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new
glossary terms.
Project 2010-07 Technical Justification Document
2
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005, and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13) Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT
agrees with that intended exclusion in principle; as it discusses in the document titled “Technical
Justification Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT
recognizes that in many cases generation Facilities are (1) staffed and the overhead portion is within
line of sight, or (2) the overhead Facility is over a paved surface. Stakeholders have generally supported
the rationale for exempting these Facilities because incorporating them into FAC-003 would offer no
reliability benefit.
Project 2010-07 Technical Justification Document
3
Thus, the SDT has maintained this exception language, but has modified it based on stakeholder input;
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, to clarify the
exemption, the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now
reads:
Generator Owner that owns an applicable qualified Facility, where a qualified Facility is an
overhead transmission line(s) that (1) extends greater than one mile or 1.609 kilometers
beyond the fenced area of the generating station switchyard to the point of interconnection
with a Transmission Owner’s Facility, or (2) does not have a clear line of sight from the
generating station switchyard fence to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines designated by
the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility, or (2) do not have a clear line of sight from the generating
station switchyard fence to the point of interconnection with a Transmission Owner’s Facility
and are: Operated at 200kV or higher; or operated below 200kV identified as an element of an
IROL under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV
identified as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
The SDT took into consideration all comments submitted in both formal comment periods, and
believes that this exemption now adequately addresses the reliability impact for a majority of the
Facilities, while balancing the efforts necessary to support the standard from all entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity. In
the case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
Project 2010-07 Technical Justification Document
4
interconnection Facility is included. Thus, the SDT proposes adding, “and generator interconnection
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
Ad Hoc Report*
X
X
Project 2010-07 Technical Justification Document
NERC Directive
FERC Order
X
X
X
X
X
X
5
IRO-005-2
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary
because PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
Project 2010-07 Technical Justification Document
6
blackstart resources to provide necessary real and reactive power to its generating resources
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, Paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to Section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but
also those outside of the control room. These include blackstart unit operators and field
switching operators in situations where SCADA capability is unavailable. As such, the
Commission believes that inclusion of periodic system restoration drills and training and review
of restoration plans in a system restoration Reliability Standard is the most effective way of
achieving the desired goal of ensuring that all participants are trained in system restoration and
that the restoration plans are up to date to deal with system changes.
Project 2010-07 Technical Justification Document
7
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
Project 2010-07 Technical Justification Document
8
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In Paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
Project 2010-07 Technical Justification Document
9
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read, “Each Generator Operator shall provide operating personnel with
the responsibility and authority to implement real-time actions to ensure the stable and reliable
operation of the Generation Facility and Generation Interconnection Facility, and the responsibility and
authority to follow the directives of reliability authorities including the Transmission Operator and
Balancing Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1
(“Each Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with
adequately trained operating personnel”) and adding a new R3 that would read: “Each Generator
Operator shall implement an initial and continuing training program for all operating personnel that
are responsible for operating the Generator Interconnection Facility that verifies the personnel’s ability
and understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "…expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
Project 2010-07 Technical Justification Document
10
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order
742, FERC reaffirmed this, stating that it is "…not modifying the Order No. 693 directive regarding
training for certain generator operator dispatch personnel, nor are we expanding a generator
operator’s responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities, and are, therefore, not
covered by Order 742. Further, the SDT believes there is no reliability gap, as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the issues database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
Paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that, “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission
Operators are not required to undergo any sort of training. The SDT does not mean to dismiss this
issue altogether, and it may be that training should be expanded to include Generator Owners,
Generator Operators, Transmission Owners, end users, and possibly others; but the development of
such requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
Project 2010-07 Technical Justification Document
11
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In Paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “…there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope, as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “…if a protective relay or equipment
failure reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to
notify its Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus,
applying R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a
relay or equipment failure on its Facility, including its interconnection Facility, it would be required to
report that to its Transmission Operator under R2.1, and the Transmission Operator is then required to
notify its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities
under R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a local-
Project 2010-07 Technical Justification Document
12
area view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, Paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “…unless such
actions would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Project 2010-07 Technical Justification Document
13
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In Paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
Project 2010-07 Technical Justification Document
14
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states: “Each Balancing Authority and Transmission Operator shall use sufficient
metering of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely
monitoring of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6
already requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read, “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Project 2010-07 Technical Justification Document
15
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
16
Technical Justification Resource Document
Project 2010-07 Generator Requirements at the Transmission Interface
Background
The SDT’s technical justification
document has not changed
substantively since it was posted in
December 2011, but the document
below has been updated to reflect
the posted changes to FAC-003-3 and
FAC-003-X.
As part of its work on Project 2010-07—Generator
Requirements at the Transmission Interface, the
standard drafting team (SDT) reviewed 34 reliability
standards and 102 requirements to determine what
changes are necessary to close a reliability gap with
respect to what is commonly known as the generator
interconnection Facility. Many of these standards and requirements had been addressed in the Final
Report from the Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad Hoc
Report) and additional standards were reviewed as a result of informal discussions with NERC and FERC
staffs.
The basis for standard modifications recommended by the Ad Hoc Group for Generator Requirements
at the Transmission Interface (Ad Hoc Group) was a few fundamental clarifications to the definitions of
Generator Owner, Generator Operator, and Transmission, along with the creation of new definitions:
one for Generator Interconnection Facility and one for Generator Interconnection Operational
Interface. The Ad Hoc Group proposed the addition of these two new definitions to 26 standards
encompassing 29 requirements (new and old), along with some modifications to FAC-003 to make it
applicable to Generator Owners under certain circumstances.
Since the publication of the Ad Hoc Report, various entities have challenged these modifications and
the recommended creation of the new definitions. The SDT has developed a more focused approach
than that of the Ad Hoc Group: to propose recommendations whereby sole-use interconnection
Facilities (at or above 100 kV) that are owned and operated by generating entities will be included in a
small set of standards and requirements previously only applicable to Transmission Owners. The SDT
agrees completely with the Ad Hoc Group’s conclusion that Generator Owners and Operators of these
sole-use generator tie-line Facilities (at voltages equal to or greater than 100 kV) should not be
registered as Transmission Owners and Transmission Operators in order to maintain reliability on the
Bulk Electric System (BES).
The SDT’s justification for this strategy is rooted in the very title of its standards project: “Generator
Requirements at the Transmission Interface.” That is, the goal and scope of the project has always
been to determine the responsibilities of those Generator Owners and Generator Operators that own
or operate an interconnection Facility (in some cases labeled a “transmission Facility”) between the
generator and the interface with the portion of the BES where Transmission Owners and Transmission
Operators take over ownership and operating responsibility. These kinds of Generator Owners and
Generator Operators do not own or operate Facilities that are part of the interconnected system;
rather, they own and operate sole-use Facilities that are connected to the boundary of the
interconnected system and as such have a limited role in providing reliability compared to those that
operate in a networked fashion beyond the point of interconnection.
While some argue that these interconnecting portions of a Generator Owner’s Facilities could be
defined as Transmission and thus require the Generator Owner and Generator Operator for the Facility
to be classified and registered as a Transmission Owner and Transmission Operator, the SDT does not
believe this is necessary to provide an appropriate level of reliability for the BES. Just as important,
such classification and registration could actually cause a reduction in reliability. Generator Owners
and Generator Operators do not need, and in some cases may be prohibited from having, a wide-area
view and responsibility for the integrated transmission system. Requiring Generator Owners and
Generator Operators to have such responsibilities would require significant training, require
substantially more data and modeling responsibilities, and detract from the entities’ primary functions:
to own and operate their generation equipment – including any Facilities owned and operated at
voltages of 100 kV or greater that connect to the interconnected system – in a reliable manner.
Additionally, the SDT believes that the industry is much more aware today of the need to include all
elements (owned and operated at 100 kV or higher) of a generator Facility in the procedures and
compliance program of the registered entity that owns or has operational responsibility of those
elements. Industry awareness was raised substantially at the time the October 17, 2010 Facility Ratings
Recommendation to Industry was issued (which included Generator Owners and specifically addressed
interconnection Facilities in the Q&A document with the statement that the alert applied to generator
interconnection tie lines that are radial only and do not serve load “if the generator is considered part
of the bulk electric system”). While this applies to a specific NERC Recommendation, the SDT considers
this compelling evidence that the paradigm for thinking about generator interconnection Facilities is
shifting.
All of this has led the SDT to its current conclusions to modify FAC-001, FAC-003, and PRC-004 and
later, PRC-005. The SDT does not believe any further modifications to standards are necessary to
maintain an appropriate level of reliability based on the revised assumption that while generator
Facilities (at 100 kV and above) will be considered by some to be transmission, Generator Owners and
Generator Operators should not be registered as Transmission Owners and Transmission Operators
simply as a result of the ownership and operation of such Facilities. Because the majority of
commenters support the SDT’s current recommendation to not adopt new terms, the SDT has elected
to focus on its standard changes and not, at this time, propose revisions to existing, or creation of new,
glossary terms.
Project 2010-07 Technical Justification Document
2
Below, the SDT discusses the changes it has proposed for FAC-001, FAC-003, and PRC-004 and the
changes it plans to propose for PRC-005 and then provides justification for not modifying any of the
additional standards and requirements it has reviewed.
Review of SDT’s Proposed Standard Changes
FAC-001-1—Facility Connection Requirements
While some stakeholders have questioned the modifications in the proposed FAC-001-1, the SDT
remains convinced that there is the potential for a reliability gap if this standard is not modified so that
it applies to a Generator Owner if and when it executes an Agreement to evaluate the reliability impact
of interconnecting a third party Facility to its existing generation interconnection Facility. The intent of
this modified language is to start the compliance clock when the Generator Owner executes an
Agreement to perform the reliability assessment required in FAC-002-1. This step is expected to occur
if a Generator Owner is compelled by a regulatory body to allow such interconnection. Assuming that a
regulatory body would require a Generator Owner to evaluate such an interconnection request, the
SDT expects the Generator Owner and the third party to execute some form of an Agreement. The SDT
intentionally excluded a specific reference to the form of Agreement (such as a feasibility study) in
deference to stakeholder suggestions to avoid comingling of commercial and reliability issues in
reliability standards.
The SDT acknowledges that the scenario described in the proposed FAC-001-1 may be rare, but in the
past (for instance, FERC ¶ 61,109 at P. 19 and 134 FERC ¶ 61,064 at P. 13), Generator Owners have
received or have been directed to execute interconnection requests for their Facilities, and the SDT
thinks it is important to clarify the responsibilities related to such a request in NERC’s Reliability
Standards. And, while the SDT acknowledges that such regulatory action might also result in the
Generator Owner being registered for other functions, such as Transmission Owner, Transmission
Planner, and/or Transmission Service Provider, it decided the proposed revision provides appropriate
reliability coverage until any additional registration is required and does not impact any Generator
Owner that never executes an Agreement as described in the standard.
FAC-003-X and FAC-003-3—Vegetation Management
The SDT and most stakeholders agree with the Ad Hoc Group recommendation that FAC-003 be
applicable to Generator Owners that own a generation interconnection Facility if that Facility contains
overhead conductors. The Ad Hoc Group originally excluded such a Facility from this requirement if its
length is less than two spans (generally one half mile from the generator property line). The SDT agrees
with that intended exclusion in principle; as it discusses in the document titled “Technical Justification
Project 2010-07 Generator Requirements at the Transmission Interface,” the SDT recognizes that in
many cases, generation Facilities are (1) staffed and the overhead portion is within line of sight or (2)
the overhead Facility is over a paved surface. Stakeholders have generally supported the rationale for
exempting these Facilities because incorporating them into FAC-003 would offer no reliability benefit.
Project 2010-07 Technical Justification Document
3
Thus, the SDT has maintained this exception language but has modified it based on stakeholder input
such that it excludes Facilities shorter than one mile which have a clear line of sight from the fenced
area of the generating switchyard to the point of interconnection. Specifically, to clarify the exemption,
the SDT has modified 4.3.1 to include a reference to line of sight. 4.3.1 of FAC-003-X now reads:
Generator Owner that owns an applicable qualified Facility, where a qualified Facility is an
overhead transmission line(s) that (1) extends greater than one mile or 1.609 kilometers
beyond the fenced area of the generating station switchyard to the point of interconnection
with a Transmission Owner’s Facility or (2) does not have a clear line of sight from the
generating station switchyard fence to the point of interconnection with a Transmission
Owner’s Facility and is operated at 200 kV and above and any lower voltage lines designated by
the Regional Entity as critical to the reliability of the electric system in the region.
4.3.1 of FAC-003-3 now reads:
Overhead transmission lines that (1) extend greater than one mile or 1.609 kilometers beyond
the fenced area of the generating station switchyard to the point of interconnection with a
Transmission Owner’s Facility or (2) do not have a clear line of sight from the generating station
switchyard fence to the point of interconnection with a Transmission Owner’s Facility and are:
Operated at 200kV or higher; or operated below 200kV identified as an element of an IROL
under NERC Standard FAC-014 by the Planning Coordinator. Operated below 200 kV identified
as an element of a Major WECC Transfer Path in the Bulk Electric System by WECC.
Both references to clear line of sight include a footnote stating: “’Clear line of sight’ means the distance
that can be seen by the average person without special instrumentation (e.g., binoculars, telescope,
spyglasses, etc.) on a clear day.”
The SDT took into consideration all comments submitted in both formal comment periods, and
believes that this exemption now adequately addresses the reliability impact for a majority of the
Facilities, while balancing the efforts necessary to support the standard from all entities.
PRC-004-2.1—Analysis and Mitigation of Transmission and Generation Protection System
Misoperations
After examining all standards it had previously reviewed, the SDT elected to propose a slight change to
PRC-004-2.1. While the SDT rejected other opportunities to “drop” the phrase “generator
interconnection Facility” into requirements because it is not typically the best way to add clarity, in the
case of PRC-004-2, the SDT fears that the phrasing of R2 (“The Generator Owner shall analyze its
generator Protection System Misoperations…”) could lead to some confusion about whether an
interconnection Facility is included. Thus, the SDT proposes adding “and generator interconnection
Project 2010-07 Technical Justification Document
4
Facility” as redlined in the draft standard. Because there is no change in applicability, and because the
SDT believes that most Generator Owners already interpret the standard in this manner, we consider
this to be a minor and not substantive change employed only to add clarity.
PRC-005-1a—Transmission and Generation Protection System Maintenance and Testing
In the concurrent 45-day comment and ballot period that ended in November 2011, several
commenters pointed out that the wording in R1 and R2 of PRC-005-1a requires the same explicit
reference to a generator interconnection Facility that was added in PRC-004-2.1 R2. The SDT agrees
and is developing revisions to PRC-005-1a. These will be posted (separate from the recirculation ballot
posting) soon.
Review of Other Standards Considered by the Standard Drafting Team
To ensure that no reliability gaps were left when the SDT shifted its strategy from the original strategy
of the Ad Hoc Group, the SDT reviewed all standards for which the Ad Hoc Group had proposed
changes, and again discussed whether making these standards applicable to Generator Owners or
Generator Operators would increase reliability with respect to generator requirements at the
transmission interface. During the 45-day concurrent comment and ballot period that ended in
November 2011, the SDT also received comments from NERC staff encouraging it to review additional
standards that NERC staff had proposed to apply to Generator Owners and Generator Operators in
NERC Compliance Process Directive #2011-CAG-001 Regarding Generator Transmission Leads
(Directive). Similarly, stakeholder commenters encouraged the SDT to review standards cited in FERC’s
Order Denying Compliance Registry Appeals of Cedar Creek Wind Energy and Milford Wind Corridor
Phase I (135 FERC ¶ 61,241) (FERC Order).
The SDT reviewed all of these standards and requirements again and continues to find clear and
technical reliability-based reasons that support not adding Generator Owner and Generator Operator
requirements to the standards. The chart below indicates where else (the Ad Hoc Report, the NERC
Directive, or the FERC Order) the standards addressed were discussed. While both the NERC Directive
and FERC Orders address specific requirements within these standards, the SDT has found it useful to
address each standard as a whole. Often, requirements within a standard, or even from standard to
standard, work in concert to ensure that there are no reliability gaps, whereas a review of a
requirement in isolation might give the impression that there is gap.
Standard
EOP-003-1
EOP-005-1
FAC-001-0
FAC-003-1 or FAC-003-2
FAC-014-2
IRO-005-2
Ad Hoc Report*
X
X
NERC Directive
FERC Order
X
X
X
X
X
X
X
Project 2010-07 Technical Justification Document
5
PER-001-0
PER-002-0
PER-003-1
PRC-001-1
TOP-001-1
TOP-004-2
TOP-006-1
TOP-008-1
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*This chart and accompanying document only address those standards in the Ad Hoc Report for which
substantive changes (change in applicability or the addition of a new requirement) were proposed.
The SDT acknowledges that both NERC and FERC have stated that neither the NERC Directive nor the
FERC Order is intended to prejudge the work of the SDT. The SDT also acknowledges that the
discussion in the FERC Order is related to specific cases in which certain entities will actually be
registered as Transmission Owners and Transmission Operators, a process that is distinct from the
SDT’s work, which assumes that once this project is complete, Generator Owners and Generator
Operators will not be registered for any other functions based on ownership of a sole-use generator
interconnection Facility. Still, because these related efforts are ongoing, the SDT thought it would be
useful to directly address some of the discussion in the Directive and the Order. The rest of this
document provides the SDT’s technical justification for limiting the scope of its work to FAC-001, FAC003, PRC-004, and PRC-005.
EOP-003-1—Load Shedding Plans (addressed in the Ad Hoc Report)
For EOP-003-1, the Ad Hoc Group originally proposed that Generator Operators be added to the
requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic
load-shedding throughout their areas. The SDT determined that this addition was unnecessary because
PRC-001 already includes the requirement that Transmission Operators coordinate their
underfrequency load shedding programs with underfrequency isolation of generating units, which
implies that Generator Operators need to provide their underfrequency settings to their respective
Transmission Operator. Further, Generator Operators typically do not have the technical expertise or
access to the data necessary for the high-level coordination that this standard requires.
EOP-005-1—System Restoration Plans (addressed in the NERC Directive)
In its Directive, NERC staff states the following by way of rationale for applying EOP-005-1
Requirements R1, R2, R5, R6, and R7 to Generator Operators:
“If GOP has blackstart capability, then EOP-005 applies, GOP restoration plan would require
coordination with TOP per the TOP Blackstart Restoration Plan. The GOP would start its
blackstart resources to provide necessary real and reactive power to its generating resources
Project 2010-07 Technical Justification Document
6
per interconnecting TOP directives. In addition, if GOP has blackstart capability the
interconnection TOP will have included this capability in its restoration planning for its area of
responsibility. If GOP does not have blackstart capability, GOP restoration plan is dependent
upon provision of real and reactive power service from interconnecting TOP, per VAR-001 and
VAR-002 requiring the GOP to follow the directives of the interconnecting TOP, compliance with
this standard/requirments is not required.”
Blackstart capability of a generating unit is unrelated to owning or operating transmission Facilities or a
generation interconnection Facility. During a system restoration event, Generator Operators provide
real and reactive power to the BES only at the direction of a Transmission Operator. The Generator
Operators are not providing Transmission Operator services through their blackstart Facilities. In
addition, many units with blackstart capability are not included in a TOP System Restoration Plan.
In FERC Order 693, paragraph 630, FERC approved EOP-005-1 and found the standard “adequately
addresses operating personnel training and system restoration plans to ensure that transmission
operators, balancing authorities and reliability coordinators are prepared to restore the
Interconnection following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and §
39.5(f) of our regulations, the Commission directs the ERO to develop a modification to EOP-005-1
through the Reliability Standards development process that identifies time frames for training and
review of restoration plan requirements.”
FERC also specifically addressed system restoration training concerns and requirements in FERC Order
693 in its review and approval of Reliability Standard EOP-005-1. In that order, FERC stated that
personnel outside a control room should be trained in system restoration, but also that this should be
included in a system restoration Reliability Standard, as follows:
627. With regard to comments that the Commission’s concerns are being addressed in NERC’s
drafting of proposed PER-005-1 Reliability Standard on operator training, we note PER-005-1
only includes Requirements on the control room personnel and not those outside of the control
room. System restoration requires the participation of not only control room personnel but also
those outside of the control room. These include blackstart unit operators and field switching
operators in situations where SCADA capability is unavailable. As such, the Commission believes
that inclusion of periodic system restoration drills and training and review of restoration plans
in a system restoration Reliability Standard is the most effective way of achieving the desired
goal of ensuring that all participants are trained in system restoration and that the
restoration plans are up to date to deal with system changes.
Project 2010-07 Technical Justification Document
7
Thus, FERC clearly found that the existing standard EOP-005-1 adequately addressed operating
personnel training and would ensure the restoration of the BES in the event of a blackstart, and further
directed that any modifications be addressed through the Reliability Standard Development Process.
Pursuant to Order 693, NERC initiated Project 2006-03, and empowered the System Restoration and
Blackstart Standard Drafting Team (SRBSDT) to modify the related standards. The SRBSDT developed
Reliability Standard EOP-005-2, which includes Generator Operator system restoration requirements
including training, restoration plans, drills, and testing of blackstart resources. In Order 749, FERC
approved EOP-005-2, which included its approval of the implementation plan for EOP-005-2. Again,
both FERC and NERC had the opportunity to identify issues with the implementation time of EOP-005-2
and declined to do so.
5. Currently effective Reliability Standard EOP-005-1 requires transmission operators, balancing
authorities, and reliability coordinators to have a restoration plan, test the plan, train operating
personnel in the restoration plan, and have the ability to restore the Interconnection using the
plans following a blackout. In Order No. 693, the Commission directed the ERO to develop,
through the Reliability Standard development process, a modification to EOP-005-1 that
identifies time frames for training and review of restoration plan requirements to simulate
contingencies and prepare operators for anticipated and unforeseen events . . .
Also, in FERC Order 749, both NERC and FERC identified the modifications to EOP-005 as
“improvements” to the standard, not changes to close a reliability gap:
10. NERC states that the proposed Reliability Standards “represent significant revision and
improvement from the current set of enforceable standards” and address the Commission’s
directives in Order No. 693 related to the EOP standards. NERC explains that, among other
enhancements, “[t]he proposed revisions now clearly delineate the responsibilities of the
Reliability Coordinator and Transmission Operator in the restoration process and restoration
planning.” NERC describes the proposed Reliability Standards as providing “specific
requirements for what must be in a restoration plan, how and when it needs to be updated and
approved, what needs to be provided to operators and what training is necessary for personnel
involved in restoration processes.
17. . . . By enhancing the rigor of the restoration planning process, the Reliability Standards
represent an improvement from the current Standards and will improve the reliability of the
Bulk-Power System. . . .
In summary, the Generator Operator blackstart requirements have been already been appropriately
addressed through the Reliability Standards Development Process. EOP-005-2 will become effective in
Project 2010-07 Technical Justification Document
8
2013 as approved by both the NERC Board of Trustees and FERC. There is no existing reliability gap
related to owning a generation interconnection Facility and Standard EOP-005-1.
FAC-014-2—Establish and Communicate System Operating Limits (addressed in the NERC Directive
and the FERC Order)
FAC-014-2, R2 states “The Transmission Operator shall establish SOLs (as directed by its Reliability
Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability
Coordinator’s SOL Methodology.”
In its Directive, NERC states, with respect to FAC-014-2: “In the event an RC directs the establishment
of an SOL, the SOL must be established in accordance with the RC’s SOL Methodology.”
In paragraphs 68 and 84 of the FERC Order, FERC states that without compliance with FAC-014, R2, the
entity in questions could “avoid establishing the system operating limit for its line or be allowed to
establish an operating limit for its line that is not consistent with the requirements of the reliability
coordinator’s methodology.”
The SDT does not believe that FAC-014-2 R2 should be revised to include Generator Operators. The
Generator Owner is required by the FERC-approved versions of FAC-008-1 R1 and FAC-009-1 and
pending FAC-008-3 R1, R2, and R6 (which has been filed for approval with FERC) to document the
Facility Ratings for a Generator Owner-owned generator interconnection circuit greater than 100kV.
The established Facility Rating must respect the most limiting applicable equipment rating in the circuit
and must consider operating limitations and ambient conditions. The thermal or ampere rating of this
circuit would equal its ampere operating limit and should be conveyed by the Generator Owner to the
Generator Operator if they are not the same entity. The operating voltage limits for this circuit are
established by the applicable Transmission Owner or Transmission Operator, not the Generator Owner
or Generator Operator.
Therefore, we believe adding the Generator Owner to FAC-014-2 R2 would be redundant. What’s
more, the SDT is concerned that entities with a limited view of the system should not be setting IROLs
or SOLs. We believe this should be the responsibility of entities with a wide-area view, as shown in the
standard today; otherwise, we are concerned that reliability may be jeopardized. Commenters –
including one from the Transmission Owner segment – have offered this same justification.
IRO-005-2—Reliability Coordination – Current Day Operations (addressed in the Ad Hoc Report)
The SDT chose not to adopt the revision to IRO-005-2 proposed by the Ad Hoc Group. This revision
would have added a new requirement that would read, “The Generator Operator shall immediately
inform the Transmission Operator of the status of the Special Protection System, including any
degradation or potential failure to operate as expected for SPS relay or control equipment under its
control.” The SDT initially determined that IRO-005-2 did not require modification because of the
Project 2010-07 Technical Justification Document
9
October 2011 retirement of the standard. In subsequent meetings, the SDT also reached the
conclusion that there is no reliability gap as PRC-001-1 R2 already requires the Generator Operator to
notify reliability entities of relay or equipment failures. The SDT believes that a Special Protection
System is a form of protection system and therefore any degradation or potential failure to operate as
expected would be required to be reported by the Generator Operator to reliability entities (Balancing
Authorities, Transmission Operators, and Reliability Coordinators).
PER Standards (PER-001-0 and PER-002-0 were addressed in the Ad Hoc Report; PER-002-0 was
addressed in the NERC Directive; and PER-003-1 was addressed in the FERC Order)
The Ad Hoc Group had proposed changes to PER-001-0—Operating Personnel Responsibility and
Authority and PER-002-0—Operating Personnel Training. For PER-001-0, the Ad Hoc Group proposed
adding a new R2 that would read “Each Generator Operator shall provide operating personnel with the
responsibility and authority to implement real-time actions to ensure the stable and reliable operation
of the Generation Facility and Generation Interconnection Facility, and the responsibility and authority
to follow the directives of reliability authorities including the Transmission Operator and Balancing
Authority.” To PER-002-0, the Ad Hoc Group proposed adding the Generator Operator to R1 (“Each
Transmission Operator, Generator Operator, and Balancing Authority shall be staffed with adequately
trained operating personnel”) and adding a new R3 that would read: “Each Generator Operator shall
implement an initial and continuing training program for all operating personnel that are responsible
for operating the Generator Interconnection Facility that verifies the personnel’s ability and
understanding to operate the equipment in a reliable manner.”
In its Directive, NERC does not address PER-001-0, but it states the following with respect to PER-002-0:
“The registered entity will develop an appropriate training program that contains the necessary
elements for the GO/GOP operating a transmission facility to understand fully the impacts of
the operation on the BPS, such as equipment involved, including protection systems, the
coordination aspects with the TO/TOP to which it is connected, and the protocols for and
impacts of operating facilities associated with the transmission facility. The objective of this
training is to ensure that the GO/GOP is completely aware of its obligations to follow the
directives of the appropriate TOP and has personnel with the skills and training to execute
these obligations in the best interest of reliability.”
These proposed changes to the PER standards have little to do with responsibilities that relate
specifically to a generator interconnection Facility. Issues related to the training of Generator
Operators existed separately from the work of Project 2010-07, and the SDT agrees that its scope limits
its efforts to standards that are directly related to generator requirements at the transmission
interface. The SDT also cites past FERC Orders as proof that this issue is not within the scope of Project
2010-07. In Order 693, FERC directed NERC to "expand the applicability of the personnel training
Reliability Standard, PER-002-0, to include (i) generator operators centrally-located at a generation
Project 2010-07 Technical Justification Document
10
control center with a direct impact on the reliable operation of the Bulk-Power System..." In Order 742,
FERC reaffirmed this, stating that it is "not modifying the Order No. 693 directive regarding training for
certain generator operator dispatch personnel, nor are we expanding a generator operator’s
responsibilities.”
Centrally-located generator operators working at a generation control center typically dispatch the
output from multiple generating units. As such, they can be called upon to comply with orders from
their Balancing Authority that may have a significant impact on the reliable operation of the BES. Their
training would be covered by proposed changes to PER-002-0 and Order 742. Generator Operators
who deal with interconnection Facilities at individual generating plants, on the other hand, typically do
not receive reliability-based orders specific to the interconnection Facilities and are therefore not
covered by Order 742. Further, the SDT believes there is no reliability gap as TOP-001-1 R3 already
requires Generator Operators to follow the directives of the appropriate Transmission Operators.
These training-related items are clearly important ones for the Commission, but the SDT does not think
it is appropriate to fold modifications to these PER standards into the scope of its work unless it is
specifically directed to do so. For now, modifications to PER-002-0 based on Order 693 directives are
already included in NERC’s Issue Database (P. 52-53) to be addressed by a future project. PER-001-0 is
not addressed in the Issues Database, but the Project 2007-03 drafting team has proposed that the
standard be retired.
The FERC Order does not address PER-001-0 or PER-002-0, but it does address PER-003-1. In
paragraphs 67 and 81 of the FERC Order, FERC expresses concern that operational control over the
transmission line breakers owned by the entities in question are not under the control of NERC
certified operators. FERC goes on to say that “Reliability Standard PER-003-001 requires NERC
certification of all operators that have responsibility for the real-time operation of the interconnected
Bulk Electric System. When switching the tie-line in or out of service, operators must have the
appropriate credentials and training to properly perform the switching and coordinate the switching to
prevent adverse impacts such as the introduction of faults on the system.”
The SDT can find no evidence that the kinds of training requirements for operating the breakers of the
generator interconnection Facility cited in the FERC Order exist elsewhere for other entities that
operate breakers on lines. For instance, Transmission Owners that are not also Transmission Operators
are not required to undergo any sort of training. The SDT does not mean to dismiss this issue
altogether, and it may be that training should be expanded to include Generator Owners, Generator
Operators, Transmission Owners, end users, and possibly others, but the development of such
requirements would have implications far beyond the scope and expertise of this team.
PRC-001-1—System Protection Coordination (addressed in the NERC Directive and the FERC Order)
Project 2010-07 Technical Justification Document
11
The NERC Directive addresses PRC-001-1 R2, R2.2, and R4. The FERC Order addresses these
requirements, along with Requirement R6.
About R2 and R4, NERC’s Directive simply states: “PRC-001-R2 requires notification and corrective
action for relay or equipment failure. R4 coordinate protection systems on major transmission lines
and interconnections with neighboring Generator Operators, Transmission Operators, and Balancing
Authorities.”
In paragraphs 64 and 78 of the FERC Order, FERC expresses concern that “there is a risk of an adverse
impact on reliability if the protection relays or protection systems on the [entity’s] line are not
coordinated with those on the transmission network facilities in its area.”
Generator Operators and the scope of protection equipment for generation interconnection Facilities
are already appropriately accounted for in this standard in requirement R2 and sub-requirement R2.2.
The language used in R2 that applies to the Generator Operator uses the general terms “relay or
equipment failures” which would include not only generator relaying, but generator interconnection
relaying in the Generator Operator’s scope as well. The Generator Operator is required to notify the
Transmission Operator and Host Balancing Authority in R2.1 “if a protective relay or equipment failure
reduces system reliability.” Requirement R2.2 requires the affected Transmission Operator to notify its
Reliability Coordinator and affected Transmission Operators and Balancing Authorities. Thus, applying
R2.2 to a Generator Operator would be redundant to R2.1. If a Generator Operator had a relay or
equipment failure on its Facility, including its interconnection Facility it would be required to report
that to its Transmission Operator under R2.1, and the Transmission Operator is then required to notify
its Reliability Coordinator and other affected Transmission Operators and Balancing Authorities under
R2.2.
PRC-001-1 R4 states, “Each Transmission Operator shall coordinate protection systems on major
transmission lines and interconnections with neighboring Generator Operators, Transmission
Operators, and Balancing Authorities.” A sole-use generator interconnection Facility does not
constitute a major transmission line or major interconnection with neighboring Generator Operators,
Transmission Operators, and Balancing Authorities. Thus, R4 should not be revised to include
Generator Operators. In general, any coordination that might be required is covered by the fact that
the Transmission Operator that is connected to a major transmission lines or interconnection has the
requirement to coordinate protection on the interconnection, and there is no reliability gap.
PRC-001-1 R6 states, “Each Transmission Operator and Balancing Authority shall monitor the status of
each Special Protection System in their area, and shall notify affected Transmission Operators and
Balancing Authorities of each change in status.” It is clearly the responsibility of the Transmission
Operator and/or Balancing Authority to monitor the Special Protection System, as they are the entity
with a wide-area view, not the responsibility of a Generator Owner/Generator Operator with a local-
Project 2010-07 Technical Justification Document
12
area view who happens to have generator interconnection Facilities in the area. The requirement
focuses on the Transmission Operator and Balancing Authority monitoring the status of each Special
Protection System in their area; there is no “area” for the Generator Operator to monitor. For these
reasons, there is no need to make this requirement applicable to Generator Operators.
TOP-001-1—Reliability Responsibilities and Authority (addressed in the Ad Hoc Report, NERC
Directive, and FERC Order)
Both the NERC Directive and the FERC Order discuss making TOP-001-1 R1 applicable to Generator
Operators. About TOP-001-1, the NERC Directive simply states: “TOP-001-1 R1 ensures personnel
assigned to operate BES transmission facilities have clear and unambiguous authority to operate those
facilities.” With respect to R1, paragraphs 68 and 83 of FERC’s Order focus on ensuring that “system
operators have the authority to take actions to maintain Bulk-Power System facilities within operating
limits.”
TOP-001-1 R1 states, “Each Transmission Operator shall have the responsibility and clear decisionmaking authority to take whatever actions are needed to ensure the reliability of its area and shall
exercise specific authority to alleviate operating emergencies.” TOP-001-1 R3 appropriately requires
the GOP to comply with reliability directives issued by the Transmission Operator “unless such actions
would violate safety, equipment, regulatory or statutory requirements.” These requirements
effectively give the Transmission Operator the necessary decision-making authority over operation of
all generator Facilities up to the point of interconnection. Thus, no changes to TOP-001-1 are
necessary.
Additionally, the Ad Hoc Group proposed adding two new requirements to TOP-001-1. The first was
proposed as R9 and read: “The Generator Operator shall coordinate the operation of its Generator
Interconnection Facility with the Transmission Operator to whom it interconnects in order to preserve
Interconnection reliability…” The SDT does not agree that TOP-001-1 needs to apply to Generator
Operators in any form. TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) already requires the Generator Operator to coordinate its
current-day, next-day, and seasonal operations with its Host Balancing Authority and Transmission
Service Provider. These entities are, in turn, required to coordinate with their respective Transmission
Operator. Additionally, TOP-002-2 R4 (proposed to be covered in the future by TOP-003-2, as outlined
in Project 2007-03’s Implementation Plan) requires each Balancing Authority and Transmission
Operator to coordinate with neighboring Balancing Authorities and Transmission Operators and with
its Reliability Coordinator. With these requirements, Generator Operators are already required to
provide necessary operations information to Transmission Operators. To require the same thing in
TOP-001-1 would be redundant.
The second new requirement proposed by the Ad Hoc Group for TOP-001-1 was R10, which was to
read: “The Transmission Operator shall have decision-making authority over operation of the
Project 2010-07 Technical Justification Document
13
Generator Interconnection Operational Interface at all times in order to preserve Interconnection
reliability.” As cited above, TOP-002-2 R3 (proposed to be covered in the future by TOP-003-2, as
outlined in Project 2007-03’s Implementation Plan) already requires the Generator Operator to
coordinate with its interconnecting Transmission Operator. Further, TOP-001-1 R3 (proposed to be
covered in the future in the proposed IRO-001-2 R2 and R3) already requires the Generator Operator
to comply with reliability directives issued by the Transmission Operator. These requirements
effectively give the Transmission Operator decision-making authority over operation of all generator
Facilities up to the point of interconnection. To require the same thing in TOP-001-1 would be
redundant.
TOP-004-2—Transmission Operations (addressed in the NERC Directive and the FERC Order)
Both the NERC Directive and the FERC Order address the application of TOP-004-2 R6 to Generator
Operators. In its Directive, NERC simply states: “TOP-004-2 R6 ensures formal policies and procedures
are formulated to provide for coordination of activities that may impact reliability.” In paragraphs 67
and 82 of the FERC Order, FERC talks about entities ensuring the development of coordination
protection to coordinate switching a generator interconnection Facility in and out of service, since
different entities have control over different ends of the line. FERC concludes that for the entities in
question, TOP-004-2 R6 must apply.
Requirement R6 and its sub-requirements state: “R6. Transmission Operators, individually and jointly
with other Transmission Operators, shall develop, maintain, and implement formal policies and
procedures to provide for transmission reliability. These policies and procedures shall address the
execution and coordination of activities that impact inter- and intra-Regional reliability, including: R6.1.
Monitoring and controlling voltage levels and real and reactive power flows, R6.2. Switching
transmission elements, R6.3. Planned outages of transmission elements, R6.4. Responding to IROL and
SOL violations.”
TOP-001-1 R3 appropriately requires the Generator Operator to comply with reliability directives
issued by the Transmission Operator. These requirements give the Transmission Operator the
necessary decision-making authority over operation of all generator Facilities, including
interconnection Facilities, up to the point of interconnection. Further, TOP-002-2 R3 requires the
Generator Owner to coordinate its current-day, next-day, and seasonal operations with its Host
Balancing Authority and Transmission Service Provider. These entities are, in turn, required to
coordinate with their respective Transmission Operators (also in TOP-002-2 R3). Each Balancing
Authority and Transmission Operator is also then required to coordinate with neighboring Balancing
Authorities and Transmission Operators and with its Reliability Coordinator (in TOP-002-2 R4). The
coordination with which NERC and FERC are concerned is already addressed by these other
requirements.
Project 2010-07 Technical Justification Document
14
The Ad Hoc Group had proposed a new requirement, R7, for TOP-004-2 that would read: “The
Generator Operator shall operate its Generator Interconnection Facility within its applicable ratings.”
The SDT does not agree that a reliability gap exists, because an operator has a fiduciary obligation to
protect a Facility for which it is operationally responsible. FAC-008-1—Facility Ratings Methodology
and FAC-009-1—Establish and Communicate Facility Ratings already infer that the reason for
establishing a ratings methodology and communicating Facility Ratings to the Reliability Coordinator,
Planning Authority, Transmission Planner, and Transmission Operator is “…for use in reliable planning
and operation of the Bulk Electric System.” Further, TOP-004-2 is proposed to be retired under the
work of the Project 2007-03 drafting team. Its requirements will either be deleted or assigned
elsewhere.
TOP-006-1—Monitoring System Conditions (addressed in the NERC Directive; the SDT believes NERC
intended to refer to TOP-006-2)
Only the NERC Directive addresses TOP-006. It states: “TOP-006-1 R3 ensures technical information is
provided to the responsible personnel; R6 ensures correct and accurate data to TOP and BA.” But PRC001-1 R1 (“Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar
with the purpose and limitations of protection system schemes applied in its area”) addresses the
necessary Generator Operator requirements with respect to TOP-006-2 R3. The SDT believes that
knowledge of the purpose and limitations of protection system schemes applied in its area (required in
PRC-001-1 R1) constitutes knowledge of “the appropriate technical information concerning protective
relays” (required in TOP-006-1 R3).
TOP-006-2 R6 states “Each Balancing Authority and Transmission Operator shall use sufficient metering
of suitable range, accuracy and sampling rate (if applicable) to ensure accurate and timely monitoring
of operating conditions under both normal and emergency situations.” FAC-001-1 R2.1.6 already
requires the Transmission Owner’s facility connection requirements to address “metering and
telecommunications.” Any generator Facility that interconnected with a Transmission Owner would
have had to meet their Facility connection and system performance requirements for metering and
telecommunications. Thus, there is no reliability gap.
TOP-008-1—Response to Transmission Limit Violations (addressed in the Ad Hoc Report)
Only the Ad Hoc Report addressed TOP-008-1, and it proposed a new requirement, R5, to TOP-008-1—
Response to Transmission Limit Violations that would read “The Generator Operator shall disconnect
the Generator Interconnection Facility when safety is jeopardized or the overload or abnormal voltage
or reactive condition persists and generating equipment or the Generator Interconnection Facility is
endangered. In doing so, the Generator Operator shall notify its Transmission Operator and Balancing
Authority impacted by the disconnection prior to switching, if time permits, otherwise, immediately
thereafter.” The SDT sees no reliability benefit to adding this requirement. TOP-001-1 R7 (“Each
Transmission Operator and Generator Operator shall not remove Bulk Electric System facilities from
service if removing those facilities would burden neighboring systems unless…”) and its parts give the
Project 2010-07 Technical Justification Document
15
Generator Operator authority over its Facilities, which would include the generator interconnection
Facility. If there is an outage, R7.1 requires the Generator Operator to notify and coordinate with its
Transmission Operator, which is required to notify the Reliability Coordinator and other affected
Transmission Operators. And as with TOP-004-2, the Project 2007-03 drafting team has proposed to
delete all of TOP-008-1’s requirements and retiring the standard.
Conclusion
The Project 2010-07 SDT is confident that the changes it has proposed address the reliability gap that
exists with respect to the responsibilities of Generator Owners and Generator Operations that own
sole-use interconnection Facilities. The changes to FAC-001, FAC-003, and PRC-004 have been
supported by stakeholders during comment periods, and there has been no strong support of technical
justification provided for bringing other standards into the scope of this project.
Project 2010-07 Technical Justification Document
16
Standards Announcement
Project 2010-07 Generator Requirements at the Transmission
Interface
Recirculation Ballot Windows Open April 24, 2012 through May 3, 2012
Now Available
Recirculation ballots for two versions of FAC-003—Transmission Vegetation Management Program
(FAC-003-X and FAC-003-3) and PRC-005-1.1a – Transmission and Generation Protection System
Maintenance and Testing are open Tuesday, April 24 2012 through 8 p.m. Eastern on Thursday, May
3, 2012.
Summary of Changes
The Generator Requirements at the Transmission Interface drafting team has posted FAC-003-X, FAC003-3, and PRC-005-1.1b (formerly PRC-005-1.1a before PRC-005-1b was approved by FERC on March
14, 2012) for recirculation ballot. The drafting team has made limited changes to these standards:
•
FAC-003-X:
The Applicability section was reformatted to make it clear that the standard applies on a
Facility by Facility basis (as in FAC-003-3), not simply to all generator interconnection
Facilities owned by a Generator Owner with at least one qualifying generator
interconnection Facility.
In the Purpose section, Right-of-Way was capitalized because it is an approved NERC
glossary term (approved with the initial version of FAC-003) and “North American
Electric Reliability Council” was changed to “North American Electric Reliability
Corporation.”
Regional Entity was added back to the Applicability section of the standard. Requirement
R4 is assigned to the Regional Entity, and the Project 2010-07 does not have the
authority, based on the scope outlined in its SAR, to modify that requirement. Thus,
Regional Entity must remain in the Applicability section.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan – this did not
modify the proposed effective date.
Note that if both FAC-003-X and FAC-003-3 are approved in this recirculation ballot, only
FAC-003-3 will be presented to NERC’s Board of Trustees. FAC-003-X has been modified
so that the generator interconnection Facility gap can be quickly addressed in the event
that neither FAC-003-2 nor FAC-003-3 is approved by FERC.
•
•
FAC-003-3:
A typo was found in the Severe VSL for R2; the previous reference to “Transmission
Owner” was changed to “responsible entity,” as in all other FAC-003-3 VSLs.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan – this did not
modify the proposed effective date.
PRC-005-1.1b:
The standard was updated to version 1.1b.
New boilerplate language, recently approved by NERC legal staff, was added to the
Effective Dates section of the standard and the Implementation Plan – this did not
modify the proposed effective date.
None of these changes are considered significant, as they do not change the scope or applicability of
their associated requirements.
Note that more substantive revisions to PRC-005-2 (under Project 2007-17 Protection System
Maintenance and Testing) were posted for a parallel 30-day formal comment period and successive
ballot through March 28, 2012. The proposed standard received 73.93% approval. The Project 201007 SDT recognizes this and supports the work of that team, whose changes eliminate the need for the
surgical addition of “generator interconnection Facility” made in PRC-005-1.1b. Because the Project
2010-07 SDT cannot predict the outcome of Project 2007-17 and wants to ensure that generator
interconnection Facilities are appropriately addressed in PRC-005 whether or not PRC-005-2 proceeds
to NERC's Board this year, it has elected to continue with its revisions to PRC-005-1.1b.
Instructions
In the recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast a
ballot; all ballot pool members may change their previously cast votes. A ballot pool member who
failed to cast a ballot during the last ballot window may cast a ballot in the recirculation ballot window.
If a ballot pool member does not participate in the recirculation ballot, that member’s vote cast in the
previous ballot will be carried over as that member’s vote in the recirculation ballot. Members of the
ballot pools associated with this project may log in and submit their votes for the standards by clicking
here.
Next Steps
Voting results will be posted and announced after the ballot windows close. If approved, the
standard(s) will be submitted to the Board of Trustees for adoption.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities that are considered by
Standards Announcement
Project 2010-07 - GOTO
2
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators do affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators. The SDT believes that properly
applying FAC-003 and PRC-005 to Generator Owners as proposed in the redline standards posted for
comment, along with applying FAC-001-1 and PRC-004-2.1a (which were approved by NERC’s Board on
February 9, 2012), supports this objective.
Before reviewing the standards, the drafting team encourages all stakeholders to read the technical
justification resource document it has provided to describe its rationale and its work thus far.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2010-07 - GOTO
3
Standards Announcement
Project 2010-07 – Generator Requirements at the Transmission Interface
Recirculation Ballot Results
Now Available
Ballots of three standards from Project 2010-07 - Generator Requirements at the Transmission
Interface concluded Thursday, May 3, 2012:
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Standard
Quorum
Approval
FAC-003-3 – Transmission Vegetation Management
Quorum: 81.72%
Approval: 87.34%
FAC-003-X – Transmission Vegetation Management
Program
Quorum: 81.94%
Approval: 87.32%
PRC-005-1.1a – Transmission and Generation Protection
System Maintenance and Testing
Quorum: 90.44%
Approval: 93.23%
Next Steps
FAC-003-3 – Transmission Vegetation Management, FAC-003-X – Transmission Vegetation
Management Program, and PRC-005-1.1a – Transmission and Generation Protection System
Maintenance and Testing will be presented to the NERC Board of Trustees for adoption and
subsequently filed with regulatory authorities.
Background
The purpose of Project 2010-07 is to ensure that all generator-owned Facilities are appropriately
covered under NERC’s Reliability Standards. While many Generator Owners and Generator Operators
operate Facilities, commonly known as generator interconnection Facilities, that are considered by
some entities to be transmission, these are most often radial Facilities that are not part of the
integrated grid. As such, they should not be subject to the same standards applicable to Transmission
Owners and Transmission Operators who own and operate Transmission Elements and Facilities that
are part of the integrated grid.
As part of the BES, generators affect the overall reliability of the BES. But registering a Generator
Owner or Generator Operator as a Transmission Owner or Transmission Operator, as has been the
solution in some cases in the past, may decrease reliability by diverting the Generator Owner’s or
Generator Operator’s resources from the operation of the equipment that actually produces electricity
– the generation equipment itself.
The drafting team’s goal is to ensure that an adequate level of reliability is maintained in the BES by
clearly describing which standards need to be applied to generator interconnection Facilities that are
not already applicable to Generator Owners or Generator Operators.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate. For more information or assistance, please contact Monica
Benson at monica.benson@nerc.net.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
Ballot Results – Project 2010-07
2
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2010 -07 Recirculation Ballot FAC-003-3
Password
Ballot Period: 4/24/2012 - 5/3/2012
Log in
Ballot Type: Recirculation
Total # Votes: 313
Register
Total Ballot Pool: 383
Quorum: 81.72 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
87.34 %
Vote:
Ballot Results: The Standard has Passed.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
96
9
80
31
94
51
1
7
5
9
383
#
Votes
1
0.8
1
1
1
1
0
0.5
0.1
0.7
7.1
#
Votes
Fraction
56
7
48
23
56
34
0
5
1
5
235
Negative
Fraction
0.889
0.7
0.857
0.885
0.875
0.895
0
0.5
0.1
0.5
6.201
Abstain
No
# Votes Vote
7
1
8
3
8
4
0
0
0
2
33
0.111
0.1
0.143
0.115
0.125
0.105
0
0
0
0.2
0.899
14
0
12
2
9
7
0
1
0
0
45
19
1
12
3
21
6
1
1
4
2
70
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Gregory S Miller
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
Ballot
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Negative
Affirmative
View
Affirmative
Abstain
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Gulf Power Company
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Paul C Caldwell
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Northern California Power Agency
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Tracy R Bibb
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Affirmative
Affirmative
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Max Emrick
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
View
Affirmative
Affirmative
Affirmative
Negative
View
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Affirmative
James Sauceda
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Mike Laney
S N Fernando
Affirmative
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=ab27c47b-bacd-4434-a92d-7df847c1143c[5/4/2012 1:15:37 PM]
View
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Brad Jones
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
View
Affirmative
Affirmative
Affirmative
Peter H Kinney
David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
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Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
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NERC Standards
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Ballot Results
Ballot Name: Project 2010 -07 Recirculation Ballot FAC-003-x
Password
Ballot Period: 4/24/2012 - 5/3/2012
Log in
Ballot Type: Recirculation
Total # Votes: 313
Register
Total Ballot Pool: 382
Quorum: 81.94 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
87.32 %
Vote:
Ballot Results: The Standard has Passed.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
95
9
80
31
94
51
1
7
5
9
382
#
Votes
1
0.8
1
1
1
1
0
0.5
0.1
0.7
7.1
#
Votes
Fraction
56
8
48
21
55
33
0
4
1
5
231
Negative
Fraction
0.903
0.8
0.857
0.875
0.873
0.892
0
0.4
0.1
0.5
6.2
Abstain
No
# Votes Vote
6
0
8
3
8
4
0
1
0
2
32
0.097
0
0.143
0.125
0.127
0.108
0
0.1
0
0.2
0.9
15
0
13
3
10
8
0
1
0
0
50
18
1
11
4
21
6
1
1
4
2
69
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Scott J Kinney
Kevin Smith
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
Ballot
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Kevin L Howes
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch
Affirmative
Affirmative
Abstain
View
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Cole C Brodine
Arnold J. Schuff
Raymond P Kinney
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
City of Alexandria
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Redding
City of Roseville
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Gulf Power Company
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Kelly Nguyen
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Michael Marcotte
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Bill Hughes
Susan E Gill-Zobitz
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Anthony L Wilson
William N. Phinney
Wesley W Gray
Sam Kokkinen
Paul C Caldwell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
NRG Energy Power Marketing, Inc.
Ocala Electric Utility
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alabama Municipal Electric Authority
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Electric Membership Corp.
Northern California Power Agency
Shane Sweet
William Bush
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Jason Fortik
Charles A. Freibert
Greg C. Parent
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Rick Keetch
David Anderson
David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Raymond Phillips
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Bob Beadle
Tracy R Bibb
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
View
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
American Wind Energy Association
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Infigen Energy US
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Douglas Hohlbaugh
Mark Ringhausen
Henry E. LuBean
Abstain
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Natalie McIntire
Edward Cambridge
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul Cummings
Affirmative
Affirmative
Affirmative
View
Affirmative
Affirmative
Max Emrick
Brian Horton
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
View
Affirmative
Affirmative
Affirmative
Negative
View
Dana Showalter
Abstain
Stephen Ricker
John R Cashin
Affirmative
James Sauceda
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Pamela C Zdenek
Alan Beckham
John J Babik
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
RES Americas Inc
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
ACES Power Marketing
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Luminant Energy
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Ravi Bantu
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Liam Noailles
Jason L Marshall
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Jones
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=d367f63f-9318-4904-a498-befaa003983b[5/4/2012 1:16:16 PM]
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View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.
JDRJC Associates
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Daniel Prowse
Dennis Kimm
William Palazzo
Joseph O'Brien
Alan Johnson
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Affirmative
Affirmative
Affirmative
Abstain
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
View
Affirmative
Affirmative
Affirmative
Peter H Kinney
David F. Lemmons
Frank R. McElvain
James A Maenner
Edward C Stein
Roger C Zaklukiewicz
Jim Cyrulewski
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
William M Chamberlain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
Donald Nelson
Diane J Barney
Affirmative
Thomas Dvorsky
Klaus Lambeck
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
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Ballot Results
Ballot Name: Project 2010 -07 PRC-005-1.1a
Password
Ballot Period: 4/24/2012 - 5/3/2012
Log in
Ballot Type: recirculation
Total # Votes: 350
Register
Total Ballot Pool: 387
Quorum: 90.44 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
93.23 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
102
8
84
28
96
51
0
7
3
8
387
#
Votes
1
0.5
1
1
1
1
0
0.6
0.2
0.8
7.1
#
Votes
Fraction
72
5
65
23
69
34
0
6
2
8
284
Negative
Fraction
0.9
0.5
0.915
0.958
0.896
0.85
0
0.6
0.2
0.8
6.619
Abstain
No
# Votes Vote
8
0
6
1
8
6
0
0
0
0
29
0.1
0
0.085
0.042
0.104
0.15
0
0
0
0
0.481
9
2
8
3
8
6
0
1
0
0
37
13
1
5
1
11
5
0
0
1
0
37
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Scott J Kinney
Kevin Smith
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Ballot
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Comments
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
FortisBC
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John Brockhan
Michael B Bax
Joseph Turano Jr.
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Curtis Klashinsky
Jason Snodgrass
Gordon Pietsch
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza
Michael Moltane
Ted Hobson
Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
Joe D Petaski
Danny Dees
Ernest Hahn
Terry Harbour
Theresa Allard
Tim Reed
Cole C Brodine
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Kevin M Largura
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Ryan Millard
Ronald Schloendorn
John C. Collins
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Green Cove Springs
City of Redding
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
Entergy
1
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dale Dunckel
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Charles H. Yeung
Michael E Deloach
Richard J. Mandes
Mark Peters
Steven Norris
NICOLE BUCKMAN
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Gregg R Griffin
Bill Hughes
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Henry Ernst-Jr
Joel T Plessinger
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Ocala Electric Utility
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Benton County
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
Kenneth Simmons
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Charles Locke
Gregory D Woessner
Norman D Harryhill
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Skyler Wiegmann
William SeDoris
David Anderson
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Robert Reuter
Sam Waters
Jeffrey Mueller
Gloria Bender
Erin Apperson
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Reza Ebrahimian
Kevin McCarthy
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Tim Beyrle
Affirmative
Nicholas Zettel
John Allen
David Frank Ronk
Abstain
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
View
View
View
View
View
View
View
View
View
View
NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Cowlitz County PUD
Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
North Carolina Eastern Municipal Power
Agency
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BP Wind Energy North America Inc
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
Castleton Energy Center
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Energy Services, Inc.
Essential Power, LLC
Exelon Nuclear
First Solar, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
GenOn Energy, Inc
Great River Energy
ICF International
Imperial Irrigation District
Invenergy LLC
JEA
Kansas City Power & Light Co.
Rick Syring
Russ Schneider
Frank Gaffney
Guy Andrews
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Cecil Rhodes
Affirmative
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Affirmative
Affirmative
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
George Tatar
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Mike D Kukla
Affirmative
Francis J. Halpin
Carla Bayer
Shari Heino
Chifong Thomas
John Walsh
Daniel Mason
Jeanie Doty
Paul Cummings
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Bob Essex
Tommy Drea
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Negative
Affirmative
Abstain
Affirmative
View
Negative
Negative
Abstain
View
View
Dana Showalter
Affirmative
Brenda J Frazer
John R Cashin
Tracey Stubbs
Patrick Brown
Michael Korchynsky
Robert Jenkins
Kenneth Dresner
David Schumann
James W Mason
Preston L Walsh
Brent B Hebert
Marcela Y Caballero
Alan Beckham
John J Babik
Brett Holland
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
View
View
NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern California Power Agency
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
Proven Compliance Solutions
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Siemens PTI
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Tom Foreman
Mike Laney
S N Fernando
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Hari Modi
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Annette M Bannon
Wayne Lewis
Mitchell E Needham
Tim Kucey
Steven Grega
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Edwin Cano
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Claire Lloyd
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Nickesha P Carrol
Donald Schopp
Louis S. Slade
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
View
View
View
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC Standards
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Massachusetts Attorney General
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
View
View
View
View
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
View
Affirmative
Affirmative
Peter H Kinney
David F. Lemmons
Brendan Kirby
James A Maenner
Roger C Zaklukiewicz
Jim Cyrulewski
Frederick R Plett
Brian Evans-Mongeon
Terry Volkmann
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J Barney
Affirmative
Thomas Dvorsky
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
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NERC Standards
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
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A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=cb69e5c0-918b-41f8-bbec-0bd89930aae3[5/4/2012 1:14:14 PM]
Exhibit H
Standard Drafting Team Roster for NERC Standards Development Project 2010-07
Drafting Team Roster
Project 2010-07 Generator Requirements at the Transmission Interface
Name and Title
Louis Slade, Jr., Chair,
Senior Electric Market
Policy Manager,
Electric Market Policy
& NERC Compliance
Samuel J. Dwyer, IV,
Consulting
Engineer, Quality
Management Services,
Regulatory
Compliance
Company and Address
Contact Info
Bio
Dominion
5000 Dominion Blvd.
Glen Allen, VA 23060
(804) 819-2871
louis.slade@do
m.com
Louis Slade spent the first seven years of his career in
distribution construction and operations before
transferring to system operations. As a system operator,
he performed Balancing Authority and Transmission
Operations functions. Slade held this position for four
years and was then promoted to Supervisor of System
Operations. In this role, which he held for 11 years, he
oversaw the Balancing Authority and Transmission
Operations functions and performed Reliability
Coordination functions. Slade was then charged with
developing and managing Dominion’s Transmission
Service Provider function, where he remained for two
years before becoming Chief System Operator,
responsible for managing staffs that performed
Balancing Authority, Reliability Coordination,
Transmission Operations, and Transmission Service
Provider functions, a position he held for five years.
AmerenUE Power
Operations Services
1901 Chouteau Ave.
St. Louis, MO 63103
(314) 554-4853
SDwyerIV@am
eren.com
Slade was then promoted to Project Manager and was
responsible for the integration of Dominion Va. Power’s
generation assets into the PJM RTO. Upon PJM
integration, he became Manager of the Market
Operations Center, which dispatches Dominion Va.
Power’s generation per PJM RTO rules and interfaces
with PJM’s operations and markets staffs. Slade held
this position for five years and then became the Senior
electric Market Police Manager, a services organization
position where he represents Dominion at NERC, PJM,
RFC, and SERC.
Samuel J. Dwyer, IV is a Consulting Engineer in the
Ameren Missouri affiliate of Ameren Corporation.
Ameren Missouri is a regulated, vertically integrated
electric and gas utility that owns more than 10,000 MW
of generation. This generation includes coal, nuclear,
conventional hydro, hydro pumped-storage and gasfired technologies. Ameren Missouri is a member of
MISO and its regional NERC regulatory agency is
SERC.
Dwyer has worked in the electric industry for over 35
years. His work has included transmission planning,
real-time generation operations, real-time transmission
operations, interconnection planning and negotiations
and generator interconnections. His current
responsibilities are focused on NERC Standard
compliance for Ameren Missouri as a generator owner.
Dwyer has received a Bachelor and Master of Science in
electrical engineering from the University of Missouri –
Columbia. He has also earned a Master of Business
Administration degree from the University of Missouri –
St. Louis. Mr. Dwyer is currently a registered
Professional Engineer in the state of Missouri.
Drafting Team Roster
Project 2010-07 Generator Requirements at the Transmission Interface
Stephen Enyeart,
Electrical Engineer,
Customer Service
Engineering
Bonneville Power
Administration
(360) 6196059
shenyeart@bpa.
gov
Stephen Enyeart is a Customer Service Engineer for
Bonneville Power Administration (BPA). In this
position, he is responsible for providing technical
support for BPA customers, especially those requesting
new transmission services of generation interconnection
(OASIS queue). He also provides planning assistance
for wind and gas turbine project interconnection studies
and technical and contractual support for the
development of generation interconnection agreements
(LGIA).
Enyeart is also responsible for developing technical
standards for interconnection; requesting, receiving, and
validating NERC compliance matters with customers
(generation projects); and assisting with commercial
interconnection requirements, rates, products, etc. per
the BPA Transmission Business Practices and Tariff
(OATT).
Previously, Enyeart worked in the private sector for
various utility consultants, most recently as the Project
Manager for design of Utility and Industrial projects. He
has a Bachelor of Science degree in Electrical
Engineering from Portland State University and is a
registered Professional Engineer in the state of Oregon,
along with a member of the Institute of
Electrical/Electronic Engineers.
Drafting Team Roster
Project 2010-07 Generator Requirements at the Transmission Interface
Bob Goss, Former
Manager, Compliance
Programs (now retired)
SERC Reliability
Corporation
2815 Coliseum Centre Drive
Suite 500
Charlotte, NC 28217
(704) 940-8207
rdgoss@bellsou
th.net
Through the end of June 2012, Bob Goss was the
Manager of Compliance Programs for SERC Reliability
Corporation. He managed and participated in
Compliance Inquires, Compliance Violation
Investigations, the Critical Infrastructure Program and
the Registration and Certification Programs. Goss also
provided support to the audit program by audit
participation and served on several interregional
working groups.
Previously Goss was with the Southeastern Power
Administration as the Deputy Assistant Administrator of
Power Resources for 23 years. He acted on behalf of the
Assistant Administrator in his absence and served as
Team Leader of Southeastern’s Operations Team and
oversaw the day-to-day activities of the Power
Operations Control Center. His work included
operations, maintenance, rehabilitations and
replacements of electrical equipment. His duties also
included supervision of capacity and energy scheduling,
transmission outage scheduling, generation outage
scheduling and meeting the compliance requirements of
North American Electric Reliability Council (NERC).
He also served on Southeastern’s contract negotiating
teams.
Goss holds a Bachelor of Business Administration from
the University of Georgia and has served as a Naval
officer and with the U.S. Army Corps of Engineers as a
construction representative and civil engineering
technician.
Drafting Team Roster
Project 2010-07 Generator Requirements at the Transmission Interface
John L. Simpson,
Transmission
Consultant
John L. Simpson
Transmission Consulting
(281) 954-1853
john.l.simpson
@att.net
John L. Simpson is a Transmission Consultant who
provides independent transmission consulting services
to IPPs and Merchant Electricity Generators in
wholesale electric power markets. He helps improve
transmission access for existing generating plants,
secures highest value interconnection service for new
generation additions, and provides consulting services
on NERC Reliability Standards requirements for utilities
and merchant generators.
Formerly Manager of Transmission Policy at RRI
Energy, Simpson has extensive experience in securing
transmission access for new generating plants and
improving transmission access capabilities for existing
generating plants by upgrading transmission
interconnection rights through new generator
interconnection requests. Simpson has provided expert
testimony and negotiated settlement agreements for
generator reactive power tariffs filed at FERC;
negotiated the Standard Large Generator
Interconnection Procedures and Agreement with
Transmission Providers and other Independent
Generators as part of FERC’s ANOPR process; and led
the efforts to secure approval of the first significant
modification to the FERC pro forma open access
transmission tariff for an individual utility, i.e., the
addition of Network Contract Demand Transmission
Service.
Simpson has a Bachelor of Science in Electrical
Engineering from the University of Colorado.
Drafting Team Roster
Project 2010-07 Generator Requirements at the Transmission Interface
Rick Terrill,
Manager of Regulatory
and Market Support
Luminant Power
500 N. Akard St
Dallas, TX 75070
(214) 875-8750
rick.terrill@lum
inant.com
Rick Terrill is the Manager of Regulatory and Market
Support for five affiliated Registered Generation Owner
Entities collectively referred to as Luminant Power, a
competitive power generation subsidiary of Energy
Future Holdings Corp. Luminant Power has more than
15,400 MW of generation capacity in the ERCOT
region, including coal, gas and nuclear powered
generation. Terrill’s current responsibilities include
managing the overall implementation of activities for
the generation fleet to promote compliance with the
applicable ERCOT and NERC regulatory requirements.
Terrill has more than 33 years of experience with
Luminant and its predecessor companies in a wide
variety of engineering, support and management roles.
In 2006, he assumed the lead responsibility for
developing the NERC compliance program for the
Luminant Power generating facilities. Since that time,
he has served as a member of three NERC Standard
Drafting Teams (SDTs) and a regional SDT, and has
participated in numerous other NERC standards
development projects. In ERCOT, Terrill is a past
member of the ERCOT Black Start Task Force, and is a
current alternate for the ERCOT CIP Working Group.
In addition, he has managed the Luminant Power
preparation and responses for six NERC compliance
audits, and has a broad range of experience with NERC
compliance for generation companies.
Mallory Huggins,
NERC Staff
Coordinator, Standards
Specialist
NERC
1325 G Street NW
Suite 600
Washington, DC 20005
(202) 644-8062
mallory.huggins
@nerc.net
Terrill received a Bachelor of Science degree in civil
engineering from the University of Oklahoma, and
earned an MBA in Management from Amber
University.
Mallory Huggins serves as a Standards Specialist for
NERC. She is responsible for facilitating three projects
related to NERC standards development (Project 201007, the Adequate Level of Reliability Task Force, and
the VRF/VSL revision project) and coordinating
industry outreach and communication for NERC’s
standards department.
Huggins has an M.A. in conflict resolution from
Georgetown University and worked for FERC’s Dispute
Resolution Service during her two years of graduate
school. She has training in facilitation, mediation, and
negotiation and earned a B.A. in rhetoric and
communication studies from the University of
Richmond, with a focus on interpersonal communication
and conflict.
| File Type | application/pdf |
| File Title | December 21, 2011 |
| Author | Holly Hawkins |
| File Modified | 2012-07-30 |
| File Created | 2012-07-30 |