NERC Petition

NERC Petition.pdf

FERC-725K, (Final Rule in RM12-9) Mandatory Reliability Standards for the SERC Region

NERC Petition

OMB: 1902-0260

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February 1, 2012
VIA ELECTRONIC FILING
Ms. Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: North American Electric Reliability Corporation
Docket No. RD12-___-000
Dear Ms. Bose:
The North American Electric Reliability Corporation (“NERC”) hereby submits
this petition in accordance with Section 215(d) (1) of the Federal Power Act (“FPA”) and
Part 39.5 of the Federal Energy Regulatory Commission’s (“FERC”) regulations seeking
approval of proposed Regional Reliability Standard PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements (“UFLS”) in the Southeastern Electric
Reliability Council (“SERC”) Region, associated Violation Severity Levels (“VSL”) and
Violation Risk Factors (“VRF”), and the implementation plan for PRC-006-SERC-01.
The proposed Regional Reliability Standard was approved by the NERC Board of
Trustees during its November 3, 2011, meeting. NERC requests the standard become
effective over a 30-month window following the effective date of a Final Rule in this

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Ms. Kimberly D. Bose
February 1, 2012
Page 2
docket as provided in the implementation plan to allow entities to respond to any changes
in UFLS settings. 1
This petition consists of the following:
•
•
•
•

•

•
•
•

this transmittal letter;
a table of contents for the entire petition;
a narrative description explaining how the proposed Regional Reliability
Standard meets FERC’s requirements;
Regional Reliability Standard PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements and Implementation Plan,
submitted for approval (Exhibit A);
the NERC Board of Trustees’ Resolution approving PRC-006-SERC-01 —
Automatic Underfrequency Load Shedding Requirements and directing it be
filed with FERC (Exhibit B);
the complete Development Record of the proposed Regional Reliability
Standard (Exhibit C);
the Standard Drafting Team roster (Exhibit D); and
the Violation Severity Level and Violation Risk Factor Guideline Analysis
(Exhibit E).

Please contact the undersigned if you have any questions.
Respectfully submitted,
/s/ Willie L Phillips
Willie L. Phillips
Attorney for North American Electric
Reliability Corporation

The implementation date of Requirement R1 is dependent on FERC adoption of the continent-wide
standard PRC-006-1, which is pending in Docket No. RM11-20-000, available at:
http://www.nerc.com/files/Final_PRC-006-1_EOP-003-2_2011.03.31.pdf.

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket No. RD12-__-000

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED SERC REGIONAL RELIABILITY
STANDARD PRC-006-SERC-01 — AUTOMATIC UNDERFREQUENCY LOAD
SHEDDING REQUIREMENTS

Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001

Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
North American Electric Reliability
Corporation

David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
david.cook@nerc.net

Willie L. Phillips
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 393-3998
(202) 393-3955 – facsimile
holly.hawkins@nerc.net
willie.phillips@nerc.net

February 1, 2012

TABLE OF CONTENTS
I.

Introduction

II. Notices and Communications

III. Background:

a. Regulatory Framework

b. Basis for Approval of Proposed Regional Reliability Standard

IV. Justification for Approval of the Proposed Regional Reliability Standard

a. Basis and Purpose of Standard PRC-006-SERC-01 – Automatic
Underfrequency Load Shedding Requirements

b. Order No. 672 Criteria

c. Additional Order No. 672 Criteria for Regional Reliability
Standards

V. Summary of the Regional Reliability Standard Development Proceedings 19
VI. Conclusion

Exhibit A — Proposed Regional Reliability Standard PRC-006-SERC-01 —
Automatic Underfrequency Load Shedding Requirements and Implementation Plan
for Approval
Exhibit B — The NERC Board of Trustees’ Resolution on the PRC-006-SERC-01 —
Automatic Underfrequency Load Shedding Requirements Regional Reliability
Standard
Exhibit C — Complete Development Record of Proposed PRC-006-SERC-01 —
Automatic Underfrequency Load Shedding Requirements Regional Reliability
Standard
Exhibit D — Standard Drafting Team Roster
Exhibit E — PRC-006-SERC-01 – Violation Severity Level and Violation Risk
Factor Analysis

INTRODUCTION
The North American Electric Reliability Corporation (“NERC”) 2 hereby requests

the Federal Energy Regulatory Commission (“FERC” or “Commission”) to approve, in
accordance with Section 215(d)(1) of the Federal Power Act (“FPA”) 3 and Section 39.5
of FERC’s regulations, 18 C.F.R. § 39.5, proposed Regional Reliability Standard, PRC006-SERC-01 – Automatic Underfrequency Load Shedding Requirements included in
Exhibit A.
This petition is the first request for FERC approval of this proposed Regional
Reliability Standard. The Regional Reliability Standard proposed will be in effect only
for applicable registered entities within the SERC region. NERC continent-wide
Reliability Standards do not presently address the issues covered in this proposed
Regional Reliability Standard.
On November 3, 2011, the NERC Board of Trustees approved PRC-006-SERC01 — Automatic Underfrequency Load Shedding Requirements for the SERC region.
NERC requests that this Regional Reliability Standard be made effective upon FERC
approval. Exhibit A to this filing sets forth the proposed Regional Reliability Standard
and Implementation Plan. Exhibit B is the NERC Board of Trustees’ resolution to
approve the proposed Regional Reliability Standard. Exhibit C contains the complete
record of development for the proposed Regional Reliability Standard. Exhibit D
includes the standard drafting team roster. Exhibit E is the Violation Severity Level
(“VSL”) and Violation Risk Factor (“VRF”) guideline analysis.

NERC has been certified by FERC as the Electric Reliability Organization (“ERO”) authorized by Section
215 of the Federal Power Act. FERC certified NERC as the ERO in its order issued July 20, 2006 in
Docket No. RR06-1-000. 116 FERC ¶ 61,062 (2006) (“ERO Certification Order).
3
16 U.S.C. 824o.

II.

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the

following:
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001

Holly A. Hawkins*
Assistant General Counsel for Standards
and Critical Infrastructure Protection
North American Electric Reliability
Corporation
Willie L. Phillips*
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
holly.hawkins@nerc.net
willie.philllps@nerc.net

David N. Cook*
Senior Vice President and General
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
david.cook@nerc.net
*Persons to be included on FERC’s service list are
indicated with an asterisk. NERC requests waiver of
FERC’s rules and regulations to permit the inclusion of
more than two people on the service list.

III.

BACKGROUND
a. Regulatory Framework
By enacting the Energy Policy Act of 2005, 4 Congress entrusted FERC with the

duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk
Power System, and with the duties of certifying an ERO that would be charged with
developing and enforcing mandatory Reliability Standards, subject to FERC approval.
Section 215 of the FPA states that all users, owners and operators of the Bulk Power
System in the United States will be subject to FERC-approved Reliability Standards.

16 U.S.C. § 824o.

b. Basis for Approval of Proposed Regional Reliability Standard
Section 39.5(a) of FERC’s regulations requires the ERO to file with FERC for its
approval each Reliability Standard that the ERO proposes to become mandatory and
enforceable in the United States, and each modification to a Reliability Standard that the
ERO proposes to be made effective. FERC has the regulatory responsibility to approve
standards that protect the reliability of the Bulk Power System. In discharging its
responsibility to review, approve, and enforce mandatory Reliability Standards, FERC is
authorized to approve those proposed Reliability Standards that meet the criteria detailed
by Congress:
FERC may approve, by rule or order, a proposed reliability
standard or modification to a reliability standard if it determines
that the standard is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. 5
Order No. 672 provides guidance on the factors FERC will consider when
determining whether proposed Reliability Standards meet the statutory criteria. 6 A
Regional Reliability Standard proposed by a Regional Entity must meet the same
standards that NERC’s Reliability Standards must meet, i.e., the Regional Reliability
Standard must be shown to be just, reasonable, not unduly discriminatory or preferential,
and in the public interest. 7 FERC’s Order No. 672 also requires additional criteria that a
Regional Reliability Standard must satisfy: A regional difference from a continent-wide
Reliability Standard must either be (1) more stringent than the continent-wide Reliability
Standard (which includes a regional standard that addresses matters that the continent5

16 U.S.C. § 824o(d)(2).
See Rules Concerning Certification of the Electric Reliability Organization; Procedures for the
Establishment, Approval and Enforcement of Electric Reliability Standards, FERC Stats. & Regs., ¶ 31,204
(2006) (“Order No. 672”) at P 344, order on reh’g, FERC Stats. & Regs. ¶ 31,212 (2006) (“Order No. 672A”).
7
Section 215(d)(2) of the FPA and 18 C.F.R. §39.5(a).
6

wide Reliability Standard does not), or (2) necessitated by a physical difference in the
Bulk Power System. 8
As noted in the SERC Regional Standards Development Procedure, SERC’s
standards are developed according to the following characteristic attributes: 9
•

Openness – Participation in the development of a SERC Regional Reliability
Standard shall be open to all organizations that are directly and materially
affected by the SERC bulk power system reliability.

•

Balance – The SERC Regional Reliability Standards Development Procedure
strives to have an appropriate balance of interests and shall not be dominated
by any two interest categories and no single interest category shall be able to
defeat a matter.

•

Inclusive – Any entity (person, organization, company, government agency,
individual, etc.) with a direct and material interest in the bulk power system in
the SERC area shall have a right to participate.

•

Fair due process – The SERC Regional Reliability Standards Development
Procedure provides for reasonable notice and opportunity for public comment.

•

Transparent – All actions material to the development of SERC Regional
Reliability Standards are transparent and information regarding the progress is
posted on the SERC website as well as through extensive email lists.

•

Due Course – Does not unnecessarily delay development of the proposed
SERC Regional Reliability Standard.

SERC Regional Standards are subject to approval by NERC, as the ERO, and FERC
before becoming mandatory and enforceable under Section 215 of the FPA. 10
NERC Reliability Standards and the SERC Regional Reliability Standards are both
enforced through the SERC Compliance Program.

Order No. 672 at P 291.
The SERC Regional Standards Development Process is available at:
http://www.serc1.org/Documents/SERC%20Standards%20Committee/SERC%20DA%20Exhibit%20C%2
0-%20Regional%20Standards%20Development%20Procedure%20(1-3-09).pdf.
10
16 U.S.C. 824o.
9

The proposed SERC Regional Reliability Standard was developed in an open,
transparent, and inclusive fashion. Specifically, the proposed Regional Reliability
Standard was developed using the SERC Regional Standards Development Procedure 11
that enables all parties with an interest in the standard to participate in its development.
NERC’s public posting of this proposed Regional Reliability Standard did not elicit any
significant technical objection. In addition, NERC has determined that the proposed
standard meets the criteria for consideration and approval as a Regional Reliability
Standard.
IV.

JUSTIFICATION FOR APPROVAL OF PROPOSED REGIONAL
RELIABILITY STANDARD
This section summarizes the development of the proposed Regional Reliability

Standard PRC-006-SERC-01 — Automatic Underfrequency Load Shedding
Requirements; describes the reliability objectives to be achieved by the Regional
Reliability Standard; explains the development history of the Regional Reliability
Standard; and demonstrates how the standard meets the FERC criteria for approval.
NERC, in its analysis and approval of the proposed Regional Reliability Standard,
determined that the standard is just, reasonable, not unduly discriminatory or preferential,
and in the public interest.
The complete development record for the proposed Regional Reliability Standard
is provided in Exhibit C and includes the development and approval process, comments
received during the industry-wide comment period, responses to those comments, ballot
information, and NERC’s evaluation of the proposed standard.

The SERC Regional Standards Development Procedure is available at:
http://www.serc1.org/Documents/SERC%20Standards%20Committee/SERC%20DA%20Exhibit%20C%2
0-%20Regional%20Standards%20Development%20Procedure%20(1-3-09).pdf.

a. Basis and Purpose of Standard PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements

The proposed Regional Reliability Standard, PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements provides regional underfrequency load
shedding (“UFLS”) requirements for registered entities in the SERC Region. UFLS
requirements had been in place at a continent-wide level and within SERC for many
years prior to implementation of FERC-approved Reliability Standards in 2007. The
SERC regional UFLS standard has been developed to be consistent with the NERC
UFLS standard. The purpose of the standard is to establish consistent and coordinated
requirements for the design, implementation, and analysis of automatic UFLS schemes
among all applicable entities within the SERC Region.
b. Order No. 672 Criteria
In Order No. 672, FERC identified criteria it will use to analyze Reliability
Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies
these factors and explains how the proposed Regional Reliability Standard has met or
exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified
reliability goal.
Order No. 672 at P 321. The proposed Reliability Standard must address a
reliability concern that falls within the requirements of section 215 of the
FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such
facilities or apply to other facilities. Such facilities include all those
necessary for operating an interconnected electric energy transmission
network, or any portion of that network, including control systems. The
proposed Reliability Standard may apply to any design of planned
additions or modifications of such facilities that is necessary to provide for
reliable operation. It may also apply to Cybersecurity protection.
6

The proposed Regional Reliability Standard, PRC-006-SERC-01, is designed to
ensure that automatic UFLS protection schemes designed by Planning Coordinators and
implemented by applicable Distribution Providers and Transmission Owners in the SERC
region are coordinated so they may effectively mitigate the consequences of an
underfrequency event.
2. Proposed Reliability Standards must be applicable to users, owners, and
operators of the bulk power system, and not others.
Order No. 672 at P 322. The proposed Reliability Standard may impose a
requirement on any user, owner, or operator of such facilities, but not on
others.
The proposed Regional Reliability Standard is only applicable to Generator
Owners, Planning Coordinators, and UFLS entities in the SERC region. The term “UFLS
entities” (as noted in NERC standard PRC-006-1) means all entities that are responsible
for the ownership, operation, or control of automatic UFLS equipment as required by the
UFLS program established by the Planning Coordinators. 12 Such entities may include
Distribution Providers and Transmission Owners.
3. Proposed Reliability Standards must consider any other relevant factors.
Order No. 672 at P 323. In considering whether a proposed Reliability
Standard is just and reasonable, we will consider the following general
factors, as well as other factors that are appropriate for the particular
Reliability Standard proposed.
Exhibit C presents an overview of the issues raised in consideration of the
proposed standard that demonstrates how industry comments are addressed in this
standard development project. All comments and concerns were addressed using the
SERC Regional Standards Development Procedure which is consensus-based, technically
12

See NERC Reliability Standard PRC-006-1, available at: http://www.nerc.com/files/PRC-006-1.pdf.

sound, and open to the public and bordering entities that may be impacted by a Regional
Reliability Standard. No other factors were identified as necessary for consideration by
the standard drafting team in the development of the proposed Regional Reliability
Standard.
4. Proposed Reliability Standards must contain a technically sound method to
achieve the goal.
Order No. 672 at P 324. The proposed Reliability Standard must be
designed to achieve a specified reliability goal and must contain a
technically sound means to achieve this goal. Although any person may
propose a topic for a Reliability Standard to the ERO, in the ERO’s
process, the specific proposed Reliability Standard should be developed
initially by persons within the electric power industry and community with
a high level of technical expertise and be based on sound technical and
engineering criteria. It should be based on actual data and lessons learned
from past operating incidents, where appropriate. The process for ERO
approval of a proposed Reliability Standard should be fair and open to all
interested persons.

The proposed Regional Reliability Standard contains a technically sound means to
achieve this goal as it adds specificity for development and implementation of UFLS
schemes in the SERC Region that is not contained in the NERC UFLS Reliability
Standard, PRC-006-1.
5. Proposed Reliability Standards must be clear and unambiguous as to what is
required and who is required to comply.
Order No. 672 at P 325. The proposed Reliability Standard should be
clear and unambiguous regarding what is required and who is required to
comply. Users, owners, and operators of the Bulk-Power System must
know what they are required to do to maintain reliability.
•

The proposed Regional Reliability Standard establishes clear and
unambiguous requirements for all applicable entities, as it detailed below:
Requirement 1 requires Planning Coordinators to include its SERC

subregion as an identified island when developing criteria for selecting
portions of the Bulk Power System that may form islands.
•

Requirement 2 requires the Planning Coordinator to select or develop an
automatic UFLS scheme (percent of load to be shed, frequency set points,
and time delays) for implementation by UFLS entities within its area that
meets the specified minimum requirements.

•

Requirement 3 requires the Planning Coordinator to conduct simulations
of its UFLS scheme for an imbalance between load and generation of
13%, 22%, and 25% for all identified islands.

•

Requirement 4 requires each UFLS entity that has a total load of 100 MW
or greater in a Planning Coordinator area in the SERC Region to
implement the UFLS scheme developed by their Planning Coordinator
within specified tolerances.

•

Requirement 5 requires each UFLS entity that has a total load less than
100 MW in a Planning Coordinator area in the SERC Region to
implement the UFLS scheme developed by their Planning Coordinator
within specified tolerances, but specifies that those entities shall not be
required to have more than one UFLS step.

•

Requirement 6 requires each UFLS entity in the SERC Region to
implement changes to the UFLS scheme which involve frequency settings,
relay time delays, or changes to the percentage of load in the scheme
within 18 months of notification by the Planning Coordinator.

•

Requirement 7 requires each Planning Coordinator to provide specified
information concerning their UFLS scheme to SERC according to the
schedule specified by SERC.

•

Requirement 8 requires each Generator Owner to provide specified
generator underfrequency and overfrequency protection information
within 30 days of a request by SERC to facilitate post-event analysis of
frequency disturbances.

6. Proposed Reliability Standards must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.
Order No. 672 at P 326. The possible consequences, including range of
possible penalties, for violating a proposed Reliability Standard should be
clear and understandable by those who must comply.
The proposed Regional Reliability Standard includes a VRF and VSL for each
requirement. The ranges of penalties for violations will be based on the applicable VRFs
and VSLs and will be administered based on the sanctions table and supporting penalty
determination process described in the FERC-approved NERC Sanction Guidelines. 13
SERC developed the VSLs and VRFs proposed for assignment to PRC-006SERC-01 in accordance with applicable NERC and FERC guidance. Exhibit E to this
filing contains the VSL and VRF guideline analysis for PRC-006-SERC-01.
7. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner.
Order No. 672 at P 327. There should be a clear criterion or measure of
whether an entity is in compliance with a proposed Reliability Standard.
It should contain or be accompanied by an objective measure of

NERC Rules of Procedure Appendix 4B, available at:
http://www.nerc.com/files/NERC_Rules_of_Procedure_EFFECTIVE_20111117.pdf.

compliance so that it can be enforced and so that enforcement can be
applied in a consistent and non-preferential manner.
Each requirement of PRC-006-SERC-01 has an associated measure of compliance
that will assist those enforcing the standard in enforcing it in a consistent and nonpreferential manner. The proposed measures are as follows:
M1. Each Planning Coordinator shall have evidence such as a
methodology, procedure, report, or other documentation indicating
that its criteria included selection of its SERC subregion(s) as an
island per Requirement R1.
M2. Each Planning Coordinator shall have evidence such as
reports or other documentation that the UFLS scheme for its area
meets the design requirements specified in Requirement R2.
M3. Each Planning Coordinator shall have evidence such as
reports or other documentation that it performed the simulations of
its UFLS scheme as required in Requirement R3.
M4. Each UFLS entity that has a total load of 100 MW or greater
in a Planning Coordinator area in the SERC Region shall have
evidence such as reports or other documentation demonstrating
that its implementation of the UFLS scheme on May 1 of each
calendar year meets the requirements of Requirement R4
(including all the data elements in Parts 4.1, 4.2, and 4.3) unless
scheme changes per Requirement R6 are in process.
M5. Each UFLS entity that has a total load less than 100 MW in a
Planning Coordinator area in the SERC Region shall have
evidence such as reports or other documentation demonstrating
that its implementation of the UFLS scheme on May 1 of each
calendar year meets the requirements of Requirement R5
(including all the data elements in Parts 5.1and 5.2) unless scheme
changes per Requirement R6 are in process.
M6. Each UFLS entity shall have evidence such as reports or other
documentation demonstrating that it has made the appropriate
scheme changes within 18 months per Requirement R6. Such
evidence is only required if the Planning Coordinator makes
changes to the UFLS scheme as specified in Requirement R6.

M7. Each Planning Coordinator shall have evidence such as
reports or other documentation that data specified in Requirement
R7 was provided to SERC in accordance with the schedule.
M8. Each Generator Owner shall have evidence such as reports or
other documentation that data specified in Requirement R8 was
provided to SERC as requested.
8. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without
regard to implementation cost.
Order No. 672 at P 328. The proposed Reliability Standard does not
necessarily have to reflect the optimal method, or “best practice,” for
achieving its reliability goal without regard to implementation cost or
historical regional infrastructure design. It should however achieve its
reliability goal effectively and efficiently.
Regional Reliability Standard PRC-006-SERC-01 achieves its reliability goal
effectively and efficiently. The proposed standard sets minimum automatic UFLS design
requirements which are equivalent to the design requirements in the SERC UFLS
program that has been in effect since September 3, 1999. The one change is the addition
of a minimum time delay requirement to prevent spurious operations. This will allow
Planning Coordinators to use current UFLS schemes if those schemes meet the
performance requirements specified in the NERC UFLS standard. That will in turn
require applicable Distribution Providers and Transmission Owners to make minimal
changes to implement their portions of the UFLS schemes.
9. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect bulk power system
reliability.
Order No. 672 at P 329. The proposed Reliability Standard must not
simply reflect a compromise in the ERO’s Reliability Standard
development process based on the least effective North American practice
— the so-called “lowest common denominator” — if such practice does
not adequately protect Bulk-Power System reliability. Although [FERC]
will give due weight to the technical expertise of the ERO, [FERC] will
12

not hesitate to remand a proposed Reliability Standard if [FERC is]
convinced it is not adequate to protect reliability.
This proposed Regional Reliability Standard does not reflect a “lowest common
denominator” approach. PRC-006-SERC-01 achieves its reliability goal of providing for
the last resort system preservation measures. The standard was designed to be consistent
with the NERC automatic UFLS standard, while adding specificity not contained in the
NERC standard for the development, coordination, implementation, and analysis of
UFLS schemes in the SERC Region.
10. Proposed Reliability Standards may consider costs to implement for smaller
entities but not at consequence of less than excellence in operating system
reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into
account the size of the entity that must comply with the Reliability
Standard and the cost to those entities of implementing the proposed
Reliability Standard. However, the ERO should not propose a “lowest
common denominator” Reliability Standard that would achieve less than
excellence in operating system reliability solely to protect against
reasonable expenses for supporting this vital national infrastructure. For
example, a small owner or operator of the Bulk-Power System must bear
the cost of complying with each Reliability Standard that applies to it.
The cost to implement for smaller entities was considered during the development
of the proposed Regional Reliability Standard, PRC-006-SERC-01. The NERC
automatic UFLS standard (PRC-006-1) requires the Planning Coordinator to identify
which entities will participate in their UFLS scheme, including the number of steps and
percent load an entity will shed. The SERC UFLS standard drafting team recognized that
UFLS entities with a load of less than 100 MW may have difficulty in implementing
more than one UFLS step and in meeting a tight tolerance.
Accordingly, Requirement R5 states that such entities shall not be required to
have more than one UFLS step, and sets their implementation tolerance to a wider level.
13

This should limit any additional cost required of smaller entities to comply with the
standard, but with minimal consequence to operating system reliability.
11. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard
while not favoring one area or approach.
Order No. 672 at P 331. A proposed Reliability Standard should be
designed to apply throughout the interconnected North American BulkPower System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be
based on a single geographic or regional model but should take into
account geographic variations in grid characteristics, terrain, weather, and
other such factors; it should also take into account regional variations in
the organizational and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and
regional variations in market design if these affect the proposed Reliability
Standard.
The proposed Regional Reliability Standard is designed on a regional basis and
will only apply to the SERC region. It is not intended to be applied throughout North
America.
12. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid.
Order No. 672 at P 332. As directed by section 215 of the FPA, [FERC]
itself will give special attention to the effect of a proposed Reliability
Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition.
Among other possible considerations, a proposed Reliability Standard
should not unreasonably restrict available transmission capability on the
Bulk-Power System beyond any restriction necessary for reliability and
should not limit use of the Bulk-Power System in an unduly preferential
manner. It should not create an undue advantage for one competitor over
another.
This proposed Regional Reliability Standard does not cause undue negative
effects on competition or restriction of the grid. Because this standard will be applied

equally across the SERC region, PRC-006-SERC-01 will not negatively affect
competition, or restrict available transmission capability within the SERC footprint.
13. The implementation time for the proposed Reliability Standards must be
reasonable.
Order No. 672 at P 333. In considering whether a proposed Reliability
Standard is just and reasonable, [FERC] will consider also the timetable
for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the
reasonableness of the time allowed for those who must comply to develop
the necessary procedures, software, facilities, staffing or other relevant
capability.

The proposed Reliability Standard will become fully effective 30 months after the
first day of the first quarter following regulatory approval. The implementation time for
the proposed Reliability Standard is reasonable, as it balances the need for reliability with
the practicability of implementation, as detailed below:
•

•

Requirement R2 shall become effective 12 months after the first day of the
first quarter following regulatory approval. This 12-month period is
needed to allow time for entities to ensure a minimum time delay of six
cycles on existing automatic UFLS relays as specified in part 2.6.

•

to assess the overall effectiveness of the UFLS schemes in the SERC
Region.
•

Requirements R4, R5, and R6 shall become effective 30 months after the
first day of the first quarter following regulatory approval. This additional
18 months is needed to allow time for any necessary changes to be made
to the existing UFLS schemes in the SERC Region.

•

Requirement R7 shall become effective six months following the effective
date of R8 of the NERC standard PRC-006-1, but no sooner than one year
following the first day of the first calendar quarter after applicable
regulatory approval of PRC-006-SERC-01. R8 of the NERC standard
requires each UFLS entity to provide UFLS data to the Planning
Coordinator. R7 of the SERC standard requires the Planning Coordinator
to provide this data to SERC.

•

Requirement R8 shall become effective 12 months after the first day of the
first quarter following regulatory approval. This 12-month period is
needed to allow time for Generator Owners to collect and make an initial
data filing.

14. The Reliability Standard development process must be open and fair.
Order No. 672 at P 334. Further, in considering whether a proposed
Reliability Standard meets the legal standard of review, we will entertain
comments about whether the ERO implemented its [FERC]-approved
Reliability Standard development process for the development of the
particular proposed Reliability Standard in a proper manner, especially
whether the process was open and fair. However, we caution that we will
not be sympathetic to arguments by interested parties that choose, for
whatever reason, not to participate in the ERO’s Reliability Standard
development process if it is conducted in good faith in accordance with the
procedures approved by [FERC].
16

SERC develops Regional Reliability Standards in accordance with Exhibit C
(SERC Regional Standards Development Procedure), which is part of SERC’s Regional
Delegation Agreement with NERC. The development process is open to any person or
entity with a legitimate interest in the reliability of the Bulk Power System. SERC
considers the comments of all stakeholders and an affirmative vote of the stakeholders
and the SERC Board of Directors are both required to approve a Regional Reliability
Standard for submission to NERC and FERC.
The proposed Regional Reliability Standard has been developed and approved by
industry stakeholders using SERC’s Regional Standards Development Procedure and
was approved by the Executive Committee of the SERC Board of Directors on
September 19, 2011. The standard was subsequently presented to, and approved by the
NERC Board of Trustees November 3, 2011. Therefore, SERC has utilized its standard
development process in good faith and in a manner that is open and fair. No commenters
disagreed with the open and fair implementation of the SERC process.
15. Proposed Reliability Standards must be balanced against other vital public
interests.
Order No. 672 at P 335. Finally, we understand that at times development
of a proposed Reliability Standard may require that a particular reliability
goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any
such balancing in its application for approval of a proposed Reliability
Standard.
There are no competing public interests with the request for approval of this
proposed Regional Reliability Standard. No comments were received that indicated the
proposed standard conflicts with other vital public interests. Therefore, it is not

necessary to balance this Reliability Standard against any other competing public
interests.
16. Proposed Reliability Standard must not conflict with prior FERC Rules or
Orders.
Order No. 672 at P 444. A potential conflict between a Reliability
Standard under development and a Transmission Organization function,
rule, order, tariff, rate schedule, or agreement accepted, approved, or
ordered by the Commission should be identified and addressed during the
ERO’s Reliability Standard Development Process.
The proposed PRC-006-SERC-01 Regional Reliability Standard does not conflict
with any other prior FERC Rules or Orders and adequately addresses the directives
identified in FERC Order No. 693.
c. Additional Order No. 672 Criteria for Regional Reliability Standards
FERC Order No. 672 also establishes additional criteria that a Regional
Reliability Standard must satisfy: “A regional difference from a continent-wide
Reliability Standard must either be (1) more stringent than the continent-wide Reliability
Standard including a regional difference that addresses matters the continent-wide
Reliability Standard does not, or (2) a Regional Reliability Standard that is necessitated
by a physical difference in the Bulk-Power System.” 14 The proposed standard satisfies
these additional criteria.
The existing NERC continent-wide standard, PRC-006-1 applies only to Planning
Coordinators, Transmission Owners, and Distribution Providers. The proposed SERC
standard, PRC-006-SERC-01, adds specificity not contained in the NERC UFLS standard
for UFLS schemes in the SERC Region. Specifically, it is designed to work in
conjunction with the NERC standard to effectively mitigate the consequences of an
14

Order No. 672 at P 291.

underfrequency event, while accommodating differences in system transmission and
distribution topology among SERC Planning Coordinators due to historical design
criteria, makeup of load demands, and generation resources.

SUMMARY OF THE REGIONAL RELIABILITY STANDARD
DEVELOPMENT PROCEEDINGS

On June 24, 2011, SERC submitted the proposed Regional Reliability Standard
for evaluation and approval to NERC in accordance with NERC’s Rules of Procedure
and Regional Reliability Standards Evaluation Procedure that was approved by NERC’s
Regional Reliability Standards Working Group. 15 NERC provided its evaluation of the
proposed PRC-006-SERC-01 standard to SERC on July 11, 2011, included in Exhibit C.
In this report, NERC provided minor formatting and wording suggestions to several
requirements. SERC modified the proposed standard in response to NERC’s suggestions.
A. Key Issues
During the 45-day NERC posting, three key issues were raised. One entity
commented that they were concerned that PRC-006-SERC-001, R2, is too prescriptive
and may not allow Planning Coordinators the flexibility and discretion needed to ensure
reliability. SERC responded that 18 different schemes are already being used within the
SERC footprint. Removing the requirements specified in R2 may lead to even more
diverse schemes and increase the probability of non-coordination within SERC. The
requirements specified in R2 are presently included within approved SERC Regional
Criteria. These requirements allow for a high degree of flexibility in developing a UFLS
scheme while promoting proper coordination among neighboring schemes both within
15

Regional Reliability Standards Evaluation Procedure, Version 1 (2009). Available at:
http://www.nerc.com/docs/sac/rrswg/NERC_Regional_Reliability_Evaluation_Procedure.pdf.

and outside SERC. There should be no coordination issues with schemes in other regions
since all of the schemes have to meet the performance characteristics in the NERC
continent-wide Standard PRC-006-1.
Another entity commented that it was not clear that the criteria proposed in this
standard are really more specific than the performance criteria proposed in the NERC
Standard PRC-006-1. It was not apparent to the commenter that there is an issue
particular to the SERC Region that is different than the rest of the Eastern
Interconnection. SERC responded that the primary purpose of the SERC regional
Standard was to provide region specific requirements for the implementation of NERC
standard PRC-006-1 requirements with the goal of adding clarity and providing
consistency. The requirements already included in the NERC UFLS standard were not
repeated in the SERC standard. In addition to providing regional consistency and
coordination, the requirements of the SERC Standard also are more stringent than the
national standard.
Finally, one entity commented that Generator Owners will only be subject to
PRC-006-SERC-01 Requirement R8 and its three sub-requirements. These requirements
and sub-requirements call for Generator Owners to provide SERC with their generator
frequency relay set points, clearing times, and maximum MW that could be separated
from the system; within 30 days of a request. Requirement R8 further qualifies the
reliability need is to “facilitate post-event analysis of frequency disturbances.” However,
the commenter noted that SERC already has the authority to gather disturbance-related
information from Generator Operators under EOP-004-1. If this is not sufficient, the
commenter argued, MOD-010-0 and MOD-012-0 require Generator Owners to provide

static and dynamic generator modeling data in accordance with the Regional Entity’s
specification. Thus, it would seem that SERC’s specification could be modified to
accommodate frequency relay data without creating any new enforceable reliability
requirements.
SERC responded that, while Attachment 1-EOP-004 NERC Disturbance Report
Form requires a report to be filed in response to an event where frequency or voltage goes
“below the under-frequency or under-voltage load shed” set points, the form does not
include the requirement to report the information spelled out in requirement R8 of PRC006-SERC-01. In addition, the MOD-010-0, MOD-012-0, and associated SERC regional
criteria, do not require that generator underfrequency and overfrequency protective
setpoints be provided. The inclusion of this requirement in the proposed standard ensures
that the SERC region receives necessary information. Including this requirement in the
standard also provides adequate notification to entities regarding providing specific data
upon request to facilitate post-event analysis of frequency disturbances.
B. Violation Risk Factors and Violation Severity Levels
The VRFs and VSLs for this standard were developed and reviewed for
consistency with NERC and FERC guidelines. 16 Analyses of the assigned VRFs and
VSLs to this standard are included in Exhibit E.

See Order on Violation Risk Factors, 119 FERC ¶ 61,145 (2007) and Order on Violation Severity Levels
Proposed by the Electric Reliability Organization, 123 FERC ¶ 61,284 (2008).

VI.

CONCLUSION
For the reasons stated above, NERC respectfully requests that FERC approve the

proposed PRC-006-SERC-01 Regional Reliability Standard, the associated proposed
definitions, and the associated Implementation Plan included in Exhibit A to this filing in
accordance with Section 215(d)(1) of the FPA and Part 39.5 of FERC’s regulations.
NERC requests that these approvals be made effective in accordance with the
Implementation Plan for PRC-006-SERC-01 included in Exhibit A to this filing.

Respectfully submitted,
Willie L. Phillips
Willie L. Phillips
Attorney for North American Electric
Reliability Corporation

Gerald W. Cauley
President and Chief Executive Officer
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326-1001

Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
North American Electric Reliability
Corporation
Willie L. Phillips
Attorney
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
holly.hawkins@nerc.net
willie.phillips@nerc.net

David N. Cook
Senior Vice President and General Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
david.cook@nerc.net

CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all
parties listed on the official service list compiled by the Secretary in this proceeding.
Dated at Washington, D.C. this 1st day of February, 2012.
/s/ Willie L. Phillips
Willie L. Phillips
Attorney for North American Electric
Reliability Corporation

Exhibit A
Proposed Regional Reliability Standard PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements and Implementation Plan for Approval

SERC UFLS Standard: PRC-006-SERC-01

Effective Dates

Requirement

Jurisdiction
Alberta

British
Columbia

Manitoba

New
Brunswick

Newfoundland

R4, R5, and R6

Nova
Scotia

Ontario

Quebec

Saskatchewan

TBD

Requirement R1 shall become effective 12 months after the first day of the first quarter following regulatory approval, but no sooner
than 12 months following regulatory approval of NERC PRC-006-1. This 12-month period is consistent with the effective date of R2 of
PRC-006-1.
Requirement R2 shall become effective 12 months after the first day of the first quarter following regulatory approval. This 12month period is needed to allow time for entities to ensure a minimum time delay of six cycles on existing UFLS relays as specified in
part 2.6.

Adopted by Board of Trustees: November 3, 2011

Page 1 of 15

USA

SERC UFLS Standard: PRC-006-SERC-01

Requirements R3 shall become effective 18 months after the first day of the first quarter following regulatory approval. This
additional six-month period is needed to allow time to perform and coordinate studies necessary to assess the overall effectiveness
of the UFLS schemes in the SERC Region.
Requirements R4, R5, and R6 shall become effective 30 months after the first day of the first quarter following regulatory approval.
This additional 18 months is needed to allow time for any necessary changes to be made to the existing UFLS schemes in the SERC
Region.
Requirement R7 shall become effective six months following the effective date of R8 of the NERC standard PRC-006-1, but no sooner
than one year following the first day of the first calendar quarter after applicable regulatory approval of PRC-006-SERC-01. R8 of the
NERC standard requires each UFLS entity to provide UFLS data to the Planning Coordinator (PC). R7 of the SERC standard requires
the PC to provide this data to SERC.
Requirement R8 shall become effective 12 months after the first day of the first quarter following regulatory approval. This 12month period is needed to allow time for Generator Owners (GO) to collect and make an initial data filing.

Adopted by Board of Trustees: November 3, 2011

Page 2 of 15

SERC UFLS Standard: PRC-006-SERC-01

Introduction

Title: Automatic Underfrequency Load Shedding Requirements

Number: PRC-006-SERC–01

Purpose: To establish consistent and coordinated requirements for the design,
implementation, and analysis of automatic underfrequency load shedding (UFLS)
programs among all SERC applicable entities.

Applicability:
4.1 Planning Coordinators
4.2 UFLS entities shall mean all entities that are responsible for the ownership,
operation, or control of UFLS equipment as required by the UFLS program
established by the Planning Coordinators. Such entities may include one or more
of the following:
4.2.1 Transmission Owners
4.2.2 Distribution Providers
4.3 Generator Owners

Background
The SERC UFLS Standard: PRC-006-SERC-1 (“SERC UFLS Standard”) was developed to
provide regional UFLS requirements to entities in SERC. UFLS requirements have been
in place at a continent-wide level and within SERC for many years prior to
implementation of federally mandated reliability compliance standards in 2007.
When reliability standards were implemented in 2007, the Federal Energy Regulatory
Commission (“FERC”), which is the government body with regulatory responsibility for
electric reliability, issued FERC Order 693, recognizing 83 NERC Reliability Standards as
enforceable by FERC and applicable to users, owners, and operators of the bulk power
system (BPS). FERC did not approve the NERC UFLS standard, PRC-006-0 in Order 693.
FERC’s reason for not approving PRC-006-0 was that it recognized PRC-006-0 as a “fill-in
the blank standard,” and regional procedures associated with the standard were not
submitted along with the standard. FERC’s ruling in Order 693 required Regional
Entities to provide the regional requirements necessary for completing the UFLS
standard.
In 2008, SERC commenced work on PRC-006-SERC-01. NERC also began work on
revising PRC-006-0 at a continent-wide level. The SERC standard has been developed to
be consistent with the NERC UFLS standard.
PRC-006-1 clearly defines the roles and responsibilities of parties to whom the standard
applies. The standard identifies the Planning Coordinator (“PC”) as the entity
responsible for developing UFLS schemes within their PC area. The regional standard
adds specificity not contained in the NERC standard for development and
implementation of a UFLS scheme in the SERC Region that effectively mitigates the
consequences of an underfrequency event.

Adopted by Board of Trustees: November 3, 2011

Page 3 of 15

SERC UFLS Standard: PRC-006-SERC-01

Requirements and Measures

R1. Each Planning Coordinator shall include its SERC subregion as an identified island in the
criteria (required by the NERC PRC standard on UFLS) for selecting portions of the BPS
that may form islands. [Violation Risk Factor: Medium] [Time Horizon: Long-term
Planning]
1.1 A Planning Coordinator may adjust island boundaries to differ from subregional
boundaries where necessary for the sole purpose of producing a contiguous
subregional island more suitable for simulation.
M1. Each Planning Coordinator shall have evidence such as a methodology,
procedure, report, or other documentation indicating that its criteria included
selection of its SERC subregion(s) as an island per Requirement R1.
R2. Each Planning Coordinator shall select or develop an automatic UFLS scheme (percent
of load to be shed, frequency set points, and time delays) for implementation by UFLS
entities within its area that meets the following minimum requirements: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning ]
2.1. Have the capability of shedding at least 30 percent of the Peak Demand (MW)
served from the Planning Coordinator’s transmission system.
2.2. Shed load with a minimum of three frequency set points.
2.3. The highest frequency set point for relays used to arrest frequency decline shall
be no lower than 59.3 Hz and not higher than 59.5 Hz.
2.3.1 This does not apply to UFLS relays with time delay of one second or longer
and a higher frequency setpoint applied to prevent the frequency from
stalling at less than 60 Hz when recovering from an underfrequency event.
2.4. The lowest frequency set point shall be no lower than 58.4 Hz.
2.5. The difference between frequency set points shall be at least 0.2 Hz but no
greater than 0.5 Hz.
2.6. Time delay (from frequency reaching the set point to the trip signal) shall be at
least six cycles.
M2. Each Planning Coordinator shall have evidence such as reports or other
documentation that the UFLS scheme for its area meets the design requirements
specified in Requirement R2.

Adopted by Board of Trustees: November 3, 2011

Page 4 of 15

SERC UFLS Standard: PRC-006-SERC-01

R3. Each Planning Coordinator, when performing design assessments specified in the NERC
PRC standard on UFLS, shall conduct simulations of its UFLS scheme for an imbalance
between load and generation of 13%, 22%, and 25% for all identified island(s) where
such imbalance equals [(load minus actual generation output) / load]. [Violation Risk
Factor: High] [Time Horizon: Long-term Planning]
M3. Each Planning Coordinator shall have evidence such as reports or other
documentation that it performed the simulations of its UFLS scheme as required
in Requirement R3.
R4. Each UFLS entity that has a total load of 100 MW or greater in a Planning Coordinator
area in the SERC Region shall implement the UFLS scheme developed by their Planning
Coordinator. UFLS entities may implement the UFLS scheme developed by the Planning
Coordinator by coordinating with other UFLS entities. The UFLS scheme shall meet the
following requirements on May 1 of each calendar year. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning]
4.1. The percent of load shedding to be implemented shall be based on the actual or
estimated distribution substation or feeder demand (including losses) of the UFLS
entities at the time coincident with the previous year actual Peak Demand.
4. 2. The amount of load in each load shedding step shall be within -1.0 and +3.0 of
the percentage specified by the Planning Coordinator (for example, if the
specified percentage step load shed is 12%, the allowable range is 11 to 15%).
4. 3. The amount of total UFLS load of all steps combined shall be within -1.0 and +5.0
of the percentage specified by the Planning Coordinator for the total UFLS load in
the UFLS scheme.
M4. Each UFLS entity that has a total load of 100 MW or greater in a Planning
Coordinator area in the SERC Region shall have evidence such as reports or other
documentation demonstrating that its implementation of the UFLS scheme on
May 1 of each calendar year meets the requirements of Requirement R4
(including all the data elements in Parts 4.1, 4.2, and 4.3) unless scheme changes
per Requirement R6 are in process.
R5. Each UFLS entity that has a total load less than 100 MW in a Planning Coordinator area
in the SERC Region shall implement the UFLS scheme developed by their Planning
Coordinator, but shall not be required to have more than one UFLS step. UFLS entities
may implement the UFLS scheme developed by the Planning Coordinator by
coordinating with other UFLS entities. The UFLS scheme shall meet the following
requirements on May 1 of each calendar year. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning].

Adopted by Board of Trustees: November 3, 2011

Page 5 of 15

SERC UFLS Standard: PRC-006-SERC-01

5.1. The percent of load shedding to be implemented shall be based on the actual or
estimated distribution substation or feeder demand (including losses) of the UFLS
entities at the time coincident with the previous year actual Peak Demand.
5.2. The amount of total UFLS load shall be within ± 5.0 of the percentage specified by
the Planning Coordinator for the total UFLS load in the UFLS scheme.
M5. Each UFLS entity that has a total load less than 100 MW in a Planning Coordinator
area in the SERC Region shall have evidence such as reports or other
documentation demonstrating that its implementation of the UFLS scheme on
May 1 of each calendar year meets the requirements of Requirement R5
(including all the data elements in Parts 5.1and 5.2) unless scheme changes per
Requirement R6 are in process.
R6. Each UFLS entity shall implement changes to the UFLS scheme which involve frequency
settings, relay time delays, or changes to the percentage of load in the scheme within
18 months of notification by the Planning Coordinator. [Violation Risk Factor: Medium]
[Time Horizon: Long-term Planning]
M6. Each UFLS entity shall have evidence such as reports or other documentation
demonstrating that it has made the appropriate scheme changes within 18
months per Requirement R6. Such evidence is only required if the Planning
Coordinator makes changes to the UFLS scheme as specified in Requirement R6.
R7. Each Planning Coordinator shall provide the following information to SERC according to
the schedule specified by SERC. [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
7.1. Underfrequency trip set points (Hz)
7.2. Total clearing time associated with each set point (sec). This includes the time
from when frequency reaches the set point and ends when the breaker opens.
7.3. Amount of previous year actual or estimated load associated with each set point,
both in percent and in MW. The percentage and the Load demand (MW) shall be
based on the time coincident with the previous year actual Peak Demand.
M7. Each Planning Coordinator shall have evidence such as reports or other
documentation that data specified in Requirement R7 was provided to SERC in
accordance with the schedule.

Adopted by Board of Trustees: November 3, 2011

Page 6 of 15

SERC UFLS Standard: PRC-006-SERC-01

R8. Each Generator Owner shall provide the following information within 30 days of a
request by SERC to facilitate post-event analysis of frequency disturbances. [Violation
Risk Factor: Lower] [Time Horizon: Long-term Planning]
8.1. Generator protection automatic underfrequency and overfrequency trip set
points (Hz).
8.2. Total clearing time associated with each set point (sec). This is defined as the
time that begins when frequency reaches the set point and ends when the
breaker opens. If inverse time underfrequency relays are used, provide the total
clearing time at 59.0, 58.5, 58.0, and 57.0 Hz.
8.3. Maximum generator net MW that could be tripped automatically due to an
underfrequency or overfrequency condition.
M8. Each Generator Owner shall have evidence such as reports or other
documentation that data specified in Requirement R8 was provided to SERC as
requested.

Adopted by Board of Trustees: November 3, 2011

Page 7 of 15

SERC UFLS Standard: PRC-006-SERC-01

Compliance

Compliance enforcement authority
SERC Reliability Corporation
Compliance monitoring and assessment process
• Compliance Audit
•

Self-Certification

•

Spot Checking

•

Compliance Violation Investigation

•

Self-Reporting

•

Complaint

Evidence retention
Each Planning Coordinator, UFLS Entity and Generator Owner shall keep data or
evidence to show compliance as identified below unless directed by SERC to
retain specific evidence for a longer period of time as part of an investigation.
Each Planning Coordinator, UFLS Entity and Generator Owner shall retain the
current evidence of each Requirement and Measure as well as any evidence
necessary to show compliance since the last compliance audit.
If a Planning Coordinator, UFLS Entity or Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found
compliant or for the retention period specified above, whichever is longer.
The compliance enforcement authority shall keep the last audit records and all
requested and submitted subsequent audit records.

Adopted by Board of Trustees: November 3, 2011

Page 8 of 15

SERC UFLS Standard: PRC-006-SERC-01

Time Horizons, Violation Risk Factors, and Violation Severity Levels

Table 1
R#
R1

Time
Horizon

VRF

Long-term
Planning

Medium

Long-term
Planning

Medium

Long-term
Planning

High

Operations
Planning

Medium

Violation Severity Level
Lower

Moderate

High

Severe

N/A

The Planning
Coordinator did not have
evidence that its criteria
included selection of its
SERC subregion(s) as an
island, with or without
adjusted boundaries.

The Planning
Coordinator's scheme
did not meet one of the
UFLS system design
requirements identified
in 2.2 through 2.6

The Planning
Coordinator's scheme
did not meet two of the
UFLS system design
requirements identified
in 2.2 through 2.6.

The Planning
Coordinator's scheme
did not meet three of
the UFLS system design
requirements identified
in 2.2 through 2.6.

The Planning
Coordinator's scheme
did not meet 2.1

N/A

The Planning
Coordinator failed to
conduct one of the
required simulations of
its UFLS scheme.

N/A

The Planning
Coordinator failed to
conduct two of the
required simulations of
its UFLS scheme.

The UFLS entity’s
implemented UFLS
scheme had one load
shedding step outside
the range specified in 4.

The UFLS entity’s
implemented UFLS
scheme had two load
shedding steps outside
the range specified in 4.

The UFLS entity’s
implemented UFLS
scheme had three or
more load shedding
steps outside the range

Adopted by Board of Trustees: November 3, 2011

OR
Four or more of the UFLS
system design
requirements identified
in 2.2 through 2.6.

Page 9 of 15

SERC UFLS Standard: PRC-006-SERC-01

Table 1
R#

Time
Horizon

VRF

Operations
Planning

Medium

Long-term
Planning

Medium

Violation Severity Level
Lower

Moderate

High

Severe

specified in 4.2.

AND

The UFLS entity's
implemented UFLS
scheme had a total load
outside the range
specified in 4.3.

N/A

The UFLS entity's
implemented UFLS
scheme had a total load
outside the range
specified in 5.2.

The UFLS entity
implemented required
scheme changes but
made them 1 to 30 days
after the scheduled
date.

The UFLS entity
implemented required
scheme changes but
made them 31 to 40
days after the scheduled
date.

The UFLS entity
implemented required
scheme changes but
made them 41 to 50
days after the scheduled
date.

The UFLS entity
implemented required
scheme changes but
made them more than
50 days after the
scheduled date
OR
The UFLS entity failed to
implement the required
scheme changes.

Long-term
Planning

Lower

The Planning
Coordinator provided
the data required in R7
to SERC 1 to 10 days

Adopted by Board of Trustees: November 3, 2011

The Planning
Coordinator provided
the data required in R7
to SERC 11 to 20 days

The Planning
Coordinator provided
the data required in R7
to SERC 21 to 30 days

The Planning
Coordinator provided
the data required in R7
to SERC more than 30

Page 10 of 15

SERC UFLS Standard: PRC-006-SERC-01

Table 1
R#

Time
Horizon

Long-term
Planning

VRF

Lower

Violation Severity Level
Lower

Moderate

High

Severe

after the scheduled
submittal date.

days after the scheduled
submittal date.

The Planning
Coordinator did not
provide to SERC one
piece of information
listed in R7.
The Generator Owner
provided the data
required in R8 to SERC
11 to 20 days after the
requested submittal
date.

The Planning
Coordinator did not
provide to SERC two
pieces of information
listed in R7.
The Generator Owner
provided the data
required in R8 to SERC
21 to 30 days after the
requested submittal
date.

The Planning
Coordinator did not
provide to SERC any of
the information listed in
R7.
The Generator Owner
provided the data
required in R8 to SERC
more than 30 days after
the requested submittal
date.

The Generator Owner
did not provide to SERC
one piece of information
listed in R8.

The Generator Owner
did not provide to SERC
two pieces of
information listed in R8.

The Generator Owner
did not provide to SERC
any of the information
listed in R8.

The Generator Owner
provided the data
required in R8 to SERC 1
to 10 days after the
requested submittal
date.

Adopted by Board of Trustees: November 3, 2011

Page 11 of 15

SERC UFLS Standard: PRC-006-SERC-01

Regional Variances

None

Interpretations

None

Guideline and Technical Basis

1. Existing UFLS schemes
Each Planning Coordinator should consider the existing UFLS programs which are in place
and should consider input from the UFLS entities in developing the UFLS scheme.
2. Basis for SERC standard requirements
SERC Standard PRC-006-SERC-01 is not a stand-alone standard, but was written to be
followed in conjunction with NERC Standard PRC-006-1. The primary focus of SERC Standard
PRC-006-SERC-01 was to provide region-specific requirements for the implementation of
the higher tier NERC standard requirements with the goals of a) adding clarity and b)
providing for consistency and a coordinated UFLS scheme for the SERC region as a whole.
Generally speaking, requirements already in the NERC standard were not repeated in the
SERC standard. Therefore, both the NERC and SERC standards must be followed to ensure
full compliance.
3. Basis for applying a percentage load shedding value to Forecast Load versus Actual Load
The Planning Coordinator will develop a UFLS scheme to meet the performance
requirements of NERC Standard PRC-006-1 Requirement R3 and SERC Standard PRC-006SERC-01 Requirement R2. This development will result in certain percentages of load for
each UFLS entity in the Planning Coordinator’s area for which automatic under frequency
load shedding must be implemented. The Planning Coordinator develops these percentages
based on forecast peak load demand. However, the UFLS entity implements these
percentages based on the previous year’s actual peak demand. Applying the same
percentage to these different base values was intentional to ensure that both the Planning
Coordinator and UFLS entities had a clear, measurable value to use in performing their
respective roles in meeting the standard. Planning Coordinators typically use forecast
demands in their work. Whereas the previous year’s actual (or estimated) demand is
typically more available to UFLS entities. Additionally, the use of percentages based on
these different base values tends to minimize the error due to the time lag between design
and actual field implementation. Since a percentage is provided by the Planning Coordinator
to the UFLS entities, any differences between the design values (i.e., forecast load) and the
implemented values (i.e., previous year’s actual) would naturally tend to match up
reasonably well. For example, if the total planning area load in MW for which UFLS was
installed during the time of implementation was slightly higher or lower than the MW value
used in the design by the Planning Coordinator, multiplying by the specified percentage
would result in an implemented load shedding scheme that also had a reasonably similar
higher or lower MW value.

Adopted by Board of Trustees: November 3, 2011

Page 12 of 15

SERC UFLS Standard: PRC-006-SERC-01

4. Basis for May 1 and 18 month time frames
Each UFLS entity must annually review that the amount of UFLS load shedding implemented
is within a certain tolerance as specified by SERC Standard PRC-006-SERC-01 Requirement
R4 or Requirement R5 by May 1 of the current year. May 1 was chosen to allow sufficient
time after the previous year’s peak occurred to make adjustments in the field to the
implementation if necessary to meet the tolerances specified in Requirement R4 or
Requirement R5. Therefore, the May 1 date applies only to implementation of the existing
percentages of load shedding specified by the Planning Coordinator. On the other hand, the
18-month time frame specified in PRC-006-SERC-01 Requirement R6 is intended to allow
sufficient budgeting, procurement, and installation time for additional equipment, or for
significant setting changes to existing equipment necessary to meet a revised load shedding
scheme design that has been specified by the Planning Coordinator. During this 18-month
transition period, the May 1 measurement of R4 or Requirement R5 would not apply.
5. Basis for smaller entity threshold of 100 MW
Most distribution substations have transformers rated in the range of 10 to 40 MVA. Usually
most transformers would serve 1 to 4 feeders and each feeder will normally carry between
8 and 10 MVA. In general, assuming that each feeder would carry 10 MW, an entity with a
load slightly greater than 100 MW would have at least 10 feeders available. For a program
with three 10 % steps, only 3 feeders would be required to have under frequency load shed
capabilities. The 100 MW threshold seems to provide adequate flexibility for implementing
load shedding in three steps for entities slightly greater than 100 MW.
Rationale:

During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from each of the
rationale text boxes was moved to this section.
Rationale for R1:
Studying the Region as an island is required by the NERC standard. Most regions have only one
or a few different UFLS schemes. Where there is more than one scheme, studying this island
demonstrates that the schemes are coordinated and performing adequately. Because there
are so many different UFLS schemes in SERC (18 different schemes were represented in the
2007 SERC UFLS study), the SDT believes that applying the schemes to each subregion as an
island is a necessary additional test of the coordination of the various UFLS schemes. Without
this additional test, a poorly performing scheme may be masked by the large number of good
performing schemes in the Region. A subregion island study, which would have a smaller
number of schemes, would be more likely to uncover the poorly performing scheme and
therefore get it fixed. This approach will result in a much better overall performance of the
UFLS programs in SERC. The SDT recognized that there may be simulation problems due to
opening the ties to utilities outside the subregion. Therefore, the subregion island boundaries
are allowed to be adjusted to produce an island more suitable for simulation.
Adopted by Board of Trustees: November 3, 2011

Page 13 of 15

SERC UFLS Standard: PRC-006-SERC-01

(Note: The SERC Subregions are identified in paragraph 4.2 of the SERC Reliability Corporation
Bylaws: “The Region is currently geographically divided into five subregions that are identified
as Southeastern, Central, VACAR, Delta, and Gateway.”)
Rationale for R2:
These requirements for the UFLS schemes in SERC have been in place for many years (except
2.6). The SDT believes that these requirements are still needed to ensure consistency for the
various schemes which are used in SERC. Part 2.6 is designed to prevent spurious operations
due to transient frequency swings.
Rationale for R3:
R4 of the NERC standard PRC-006-1 requires the PC to conduct assessments of UFLS schemes
through dynamic simulations to verify that they meet performance requirements for
generation/load imbalances of up to 25%. This requirement defines specific imbalances that are
to be studied within SERC. The 13% and 22% levels were determined from simulations of the
worst case frequency overshoot for the UFLS schemes in SERC.
Rationale for R4:
The SDT believes it is necessary to put a requirement on how well the UFLS scheme is
implemented. This requirement specifies how close the actual load shedding amounts must be
to the percentage of load called for in the scheme. A 4 percentage point range is allowed for
each individual step, but the allowed range for all steps combined is 6 percentage points.
Rationale for R5:
The SDT believes it is necessary to put a requirement on how well the UFLS scheme is
implemented. This requirement specifies how close the actual load shedding amounts must be
to the percentage of load called for in the scheme. The SDT recognizes that UFLS entities with a
load of less than 100 MW may have difficulty in implementing more than one UFLS step and in
meeting a tight tolerance. The basis of the 100 MW comes from typical feeder load dropped by
UFLS relays, and the use of a 100 MW threshold in other regional UFLS standards.
Rationale for R6:
The SDT believes it is necessary to put a requirement on how quickly changes to the scheme
should be made. This requirement specifies that changes must be made within 18 months of
notification by the PC. The 18 month interval was chosen to give a reasonable amount of time
for making changes in the field. All of the SERC region has existing UFLS schemes which, based
on periodic simulations, have provided reliable protection for years. Events which result in
islanding and an activation of the UFLS schemes are extremely rare. Therefore, the SDT does
not believe that changes to an existing UFLS scheme will be needed in less than 18 months.
However, if a PC desires that changes to the UFLS scheme be made faster than that, then the
PC may request the implementation to be done sooner than 18 months. The UFLS entity may
oblige but will not be required to do so.

Adopted by Board of Trustees: November 3, 2011

Page 14 of 15

SERC UFLS Standard: PRC-006-SERC-01

Rationale for R7:
The NERC standard requires that a UFLS database be maintained by the Planning Coordinator.
This requirement specifies what data must be reported to SERC. A SERC UFLS database is
needed to facilitate data sharing across the SERC Region, with other regions, and with NERC.
Rationale for R8:
The SDT believes that generator over and under frequency tripping data is needed to
supplement the UFLS data provided by the Planning Coordinator for post-event analysis of
frequency disturbances. This requirement states what data must be reported to SERC by the
Generator Owners.
Since the inverse time curve cannot easily be placed into the SERC database, four clearing times
based on data from the curve are requested. These clearing times are intended to cover a
range of frequencies needed for event replication as well as provide information about
generators that trip at a higher frequency than is allowed by the NERC standard.
Version History

Version

Date

Action

September 19,
2011

SERC Board Approved

November 3,
2011

Adopted by NERC Board of Trustees

Adopted by Board of Trustees: November 3, 2011

Change Tracking

Page 15 of 15

Implementation Plan for Standard PRC-006-SERC-01
Automatic Underfrequency Load Shedding (UFLS) Requirements
Summary
The SERC UFLS Standard was developed to establish consistent and coordinated requirements
for the design, implementation, and analysis of automatic underfrequency load shedding (UFLS)
programs among all SERC applicable entities.
Prerequisite approvals
None
Modified standards
None
Compliance with standards
This standard is applicable to the Planning Coordinator (PC), Generator Owner (GO), and UFLS
entities. UFLS entities shall mean all entities that are responsible for the ownership, operation,
or control of UFLS equipment as required by the UFLS program established by the Planning
Coordinators. Such entities may include Transmission Owners (TO) and Distribution Providers
(DP).
Proposed effective dates
Requirement R1 shall become effective 12 months after the first day of the first quarter following
regulatory approval, but no sooner than 12 months following regulatory approval of NERC PRC006-1. This 12-month period is consistent with the effective date of R2 of PRC-006-1.
Requirement R2 shall become effective 12 months after the first day of the first quarter following
regulatory approval. This 12-month period is needed to allow time for entities to ensure a
minimum time delay of six cycles on existing UFLS relays as specified in part 2.6.
Requirements R3 shall become effective 18 months after the first day of the first quarter
following regulatory approval. This additional six-month period is needed to allow time to
perform and coordinate studies necessary to assess the overall effectiveness of the UFLS
schemes in the SERC Region.
Requirements R4, R5, and R6 shall become effective 30 months after the first day of the first
quarter following regulatory approval. This additional 18 months is needed to allow time for any
necessary changes to be made to the existing UFLS schemes in the SERC Region.
Requirement R7 shall become effective six months following the effective date of R8 of the
NERC standard PRC-006-1, but no sooner than one year following the first day of the first
calendar quarter after applicable regulatory approval of PRC-006-SERC-1. R8 of the NERC
standard requires each UFLS entity to provide UFLS data to the Planning Coordinator (PC). R7
of the SERC standard requires the PC to provide this data to SERC.

Requirement R8 shall become effective 12 months after the first day of the first quarter following
regulatory approval. This 12-month period is needed to allow time for Generator Owners (GO)
to collect and make an initial data filing.
Retired standards
None

SERC UFLS Std_PRC-006-SERC-01 Implementation Plan (06-15-11).docx

Exhibit B
The NERC Board of Trustees’ Resolution on the PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements Regional Reliability Standard

FURTHER RESOLVED, that the board approves the associated implementation plan, which
provides the following (Exhibit J):
(a) Upon regulatory approval, the standard will be mandatory and enforceable (with monetary
penalties for non-compliance) to all applicable NERC registered entities within the ReliabilityFirst
footprint;

FURTHER RESOLVED, that the board approves the Violation Risk Factors and the Violation Severity
Levels for the proposed MOD-025-1-RFC-1 – Reactive Power Capability Reliability Standard (Exhibit K);
FURTHER RESOLVED, that NERC Staff shall make the appropriate filings with ERO governmental
authorities.
Reliability Standards: IRO-006-TRE-1: IRO and SOL Mitigation in the ERCOT Interconnection
On motion of Paul Barber, the board approved the following resolutions:
RESOLVED, that the board approves the IRO-006-TRE-1: IRO and SOL Mitigation in the ERCOT
Interconnection Regional Reliability Standard (Exhibit L);
FURTHER RESOLVED, that the board approves the associated implementation plan, which
provides the following (Exhibit M):
(a) An effective date of the first day of the first calendar quarter after applicable regulatory
approval.
FURTHER RESOLVED, that the board approves the Violation Risk Factors and the Violation
Severity Levels for the proposed IRO-006-TRE-1: IRO and SOL Mitigation in the ERCOT Interconnection
Regional Reliability Standard d (Exhibit N);
FURTHER RESOLVED, that NERC Staff shall make the appropriate filings with ERO governmental
authorities.
Reliability Standards: PRC-006-SERC-1: Automatic Underfrequency Load Shedding (UFLS)
Requirements
On motion of Paul Barber , the board approved the following resolutions:
RESOLVED, that the board approves the PRC-006-SERC-01 – Automatic Underfrequency Load
Shedding (UFLS) Requirements Regional Reliability Standard (Exhibit O);
FURTHER RESOLVED, that the board approves the associated implementation plan, which
provides the following (Exhibit P):

Board of Trustees
Draft Minutes – November 3, 2011

(b) The implementation is staged over a 30-month window to allow entities to respond to any changes
in UFLS settings due to this standard. In addition, the implementation date of Requirement R1 is
dependent on FERC adoption of the continent-wide standard PRC-006-1.

FURTHER RESOLVED, that the board approves the Violation Risk Factors and the Violation
Severity Levels for the proposed PRC-006-SERC-01 – Automatic Underfrequency Load Shedding (UFLS)
Requirements Regional Reliability Standard (Exhibit Q);
FURTHER RESOLVED, that NERC Staff shall make the appropriate filings with ERO
governmental authorities.
NERC Rules of Procedure Nonsubstantive Capitalization and Definition Changes
Rebecca Michael, associate general counsel, presented for approval the nonsubstantive capitalization
and definition changes to NERC’s Rules of Procedure.
On motion of Bruce Scherr , the board approved the following resolutions:
RESOLVED, that the board approves the proposed revisions to the NERC Rules of Procedure as
set out in Agenda Item 7 to the board’s November 3, 2011 agenda (Exhibit R);
FURTHER RESOLVED, that the board approves the proposed changes to all existing Appendices
to the Rules of Procedure (Appendices 3A, 3B, 3C, 4A, 4B, 4C, 4D, 4E, 5A, 5B, 6, and 8) (Exhibit S);
FURTHER RESOLVED, that the board approves the proposed new Appendix 2, Definitions of
Terms Used in the Rules of Procedure (Exhibit T);
FURTHER RESOLVED, that NERC Staff shall make the appropriate filings with ERO governmental
authorities.
At the conclusion of this presentation, Chair Anderson invited discussion regarding the recommended
substantive changes to the Rules of Procedure following the discussion occurring the previous day at
the Member Representatives Committee meeting. No trustee responded.
Reinstatement of NERC Rules of Procedure Section 402.1.3.2
Ms. Michael reviewed and requested board approval for the reinstatement of NERC Rules of Procedure
Section 402.1.3.2
On motion of Dave Goulding, the board approved the following resolution:
WHEREAS, the October 7, 2011 order of the Federal Energy Regulatory Commission (“FERC”)
denied NERC’s request to remove Section 402.1.3.2 from NERC’s Rules of Procedure and directed NERC
to reinstate Section 402.1.3.2; and
Board of Trustees
Draft Minutes – November 3, 2011

Exhibit C
Complete Development Record of Proposed PRC-006-SERC-01 — Automatic
Underfrequency Load Shedding Requirements Regional Reliability Standard

Regional Reliability Standards - Under Development
Standard
No.

Title

Regional
Status

Dates

NERC Status

SERC Reliability Corporation (SERC)
Info(6)
Submit
Comments
Comment Form(5)

PRC-006SERC-01

Automatic
Underfrequency
Load Shedding

NERC Board
Adopted
November 3,
2011

06/29/11 08/15/11

PRC-006-SERC01(4)
Implementation
Plan(3)
Comments
Received(2)
Consideration of
Comments(1)

Consideration of Comments on Regional Reliability Standard Automatic
Underfrequency Load Shedding - PRC-006-SERC-01
The Regional Reliability Standards Working Group thanks all commenter’s who submitted
comments on the Regional Reliability Standard Automatic Underfrequency Load Shedding.
These standards were posted for a 45-day public comment period from June 29, 2011
through August 15, 2011. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 9 sets of comments,
including comments from 15 different people from approximately 13 companies
representing 5 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/regional_standards/regional_reliability_standards_under_develo
pment.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 404-446-2560 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

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

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency
Load Shedding PRC-006-SERC-01

Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.

Was the proposed standard developed in a fair and open process, using the associated
Regional Reliability Standards Development Procedure? ........................................... 5
Does the proposed standard pose an adverse impact to reliability or commerce in a
neighboring region or interconnection? ................................................................... 6
Does the proposed standard pose a serious and substantial threat to public health,
safety, welfare, or national security? ...................................................................... 8
Does the proposed standard pose a serious and substantial burden on competitive
markets within the interconnection that is not necessary for reliability? ...................... 9
Does the proposed regional reliability standard meet at least one of the following
criteria?............................................................................................................ 10
•
The proposed standard has more specific criteria for the same requirements
covered in a continent-wide standard
•
The proposed standard has requirements that are not included in the
corresponding continent-wide reliability standard
•
The proposed regional difference is necessitated by a physical difference in the
bulk power system.
If you have any other comments that you have not already provided in the response to
the prior questions, please provide them here. ...................................................... 13

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

Brent Ingebrigtson

LG&E and KU Energy

Dominion

No additional members listed.
2.

Group

Louis Slade

Additional Member Additional Organization Region Segment Selection
1. Michael Gildea

EMP NERC Compliance MRO

5, 6

2. Mike Garton

EMP NERC Compliance NPCC

5, 6

3. Connie Lowe

EMP NERC Compliance SERC

1, 3, 5, 6

4. Michael Crowley

ET Compliance

SERC

1, 3

5. Matt Woodzell

F&H

SERC

6. Chip Humphrey

F&H

RFC

Group

Howard Gugel

NERC Staff Technical Review

No additional members listed.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Individual

Laura Lee

Duke Energy

Individual

John Bee

Exelon

Individual

RoLynda Shumpert

South Carolina Electric and Gas

Individual

Jason Snodgrass

Georgia Transmission Corporation

Individual

Kelsey Colvin

MISO

Individual

Michelle R. D'Antuono

Occidental Chemical Corporation

X
X

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

1. Was the proposed standard developed in a fair and open process, using the associated Regional
Reliability Standards Development Procedure?
Summary Consideration:

Organization

Yes or No

LG&E and KU Energy

Yes

Dominion

Yes

NERC Staff Technical Review

Yes

Duke Energy

Yes

Exelon

Yes

South Carolina Electric and
Gas

Yes

Georgia Transmission
Corporation

Yes

Question 1 Comment

MISO
Occidental Chemical
Corporation

Yes

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

2. Does the proposed standard pose an adverse impact to reliability or commerce in a neighboring
region or interconnection?
Summary Consideration:

Organization

Yes or No

LG&E and KU Energy

Dominion

NERC Staff Technical Review

Duke Energy

Question 2 Comment

Exelon
South Carolina Electric and
Gas

Georgia Transmission
Corporation

MISO

MISO is concerned that PRC-006-SERC-001 R2 is too prescriptive and may not allow Planning
Coordinators the flexibility and discretion needed to ensure reliability. The Planning Coordinator is
tasked with designing the UFLS system and coordinating that system with neighboring systems.
PRC-006-SERC-001 R2 specifies acceptable ranges and limits in R2.3, R2.4, R2.5 and R2.6 for the
UFLS design. The standard makes no provisions to accommodate a determination by a PC that the
best performing design does not fit in with the specified set points and ranges in the standard. As
noted in the standard, the set points specified in R2 reflect historic practice, but there may be sound
technical justification to deviate from the set points scheme PRC-006-SERC-001 R2 proscribes. It is
possible that effective coordination with neighboring systems may require a different approach (e.g.
entities in MRO are investigating the reliability benefits of setting the frequency set point blocks at

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 2 Comment
less than 0.2 Hz apart to create finer system control). The explicit set point requirements in R2
would prohibit innovation/coordination of system design that deviated from standard without regard
to the reliability benefits of deviating from historic practice.

Response: This is a technical comment that was previously addressed.
Based on the 2007 UFLS study there are already 18 different schemes being used within the SERC footprint.
Removing the requirements specified in R2 may lead to even more diverse schemes and increase the probability of
non-coordination within SERC. The requirements specified in R2 are presently included within approved SERC
Regional Criteria. These SDT believes these requirements allow for a high degree of flexibility in developing a UFLS
scheme while promoting proper coordination among neighboring schemes both within and outside SERC. The SDT
does not believe there will be coordination issues with schemes in other regions since all of the schemes have to
meet the performance characteristics in the NERC Standard.
Occidental Chemical
Corporation

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

3. Does the proposed standard pose a serious and substantial threat to public health, safety, welfare, or
national security?
Summary Consideration:

Organization

Yes or No

LG&E and KU Energy

Dominion

NERC Staff Technical Review

Duke Energy

Exelon

South Carolina Electric and
Gas

Georgia Transmission
Corporation

Question 3 Comment

MISO
Occidental Chemical
Corporation

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

4. Does the proposed standard pose a serious and substantial burden on competitive markets within
the interconnection that is not necessary for reliability?
Summary Consideration:

Organization

Yes or No

LG&E and KU Energy

Dominion

NERC Staff Technical Review

Duke Energy

Question 4 Comment

Exelon
South Carolina Electric and
Gas

Georgia Transmission
Corporation

MISO
Occidental Chemical
Corporation

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

5. Does the proposed regional reliability standard meet at least one of the following criteria?
•

The proposed standard has more specific criteria for the same requirements covered in a
continent-wide standard

•

The proposed standard has requirements that are not included in the corresponding continentwide reliability standard

•

The proposed regional difference is necessitated by a physical difference in the bulk power
system.

Summary Consideration:

Organization

Yes or No

LG&E and KU Energy

Yes

Dominion

Yes

NERC Staff Technical Review

Yes

Duke Energy

Yes

Exelon

Question 5 Comment

[A] This regional standard is not necessary for GOs due to the work that is being done under NERC
Project 2007-09, PRC-024, "Generator Performance During Frequency and Voltage Excursions,"
and therefore suggest that the SERC UFLS Standard remove GOs from applicability section.
[B] It is not clear that the criteria proposed in this standard are really more specific than the
performance criteria proposed in the NERC Standard PRC-006,"Development and Documentation
of Regional UFLS Programs," currently at the FERC. The intent of the threshold for additional
Regional Standards is to address a Regional issue. There doesn’t appear to be a particular issue to
the SERC Region that is different than the rest of the Eastern Interconnection. Changing a setpoint
value that already is an outcome of the performance criteria doesn’t necessarily provide additional
specificity. For a Region to have requirements that are not included in the continent-wide Standard

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 5 Comment
is problematic, there should be some geographic or electric justification for such a difference,
otherwise the Requirements should be incorporated into the continent-wide Standard. Simply
adding a Requirement that is not in the pending NERC Standard does not make the Regional
Standard necessary. It is not clear that there is a physical difference between the power system of
the SERC Region as compared with the rest of the Eastern Interconnection.

Response: This same concern was previously addressed.
A. Requirement R7 of the SERC UFLS standard requires additional generator data be provided to SERC above what
is included in the current draft of PRC-024. The SDT feels this additional data is needed to adequately perform post
event analysis of frequency disturbances. The SDT therefore believes that this standard should be applicable to
GO’s
B. The primary purpose of the SERC regional Standard was to provide region specific requirements for the
implementation of NERC standard PRC-006-1 requirements with the goal of adding clarity and providing
consistency. The requirements already in the NERC standard were not repeated in the SERC standard. Not only do
the requirements of the SERC Standard provide regional consistency and coordination, they also are more stringent
than the national standard.
South Carolina Electric and
Gas

Yes

The proposed standard has more specific criteria for the same requirements covered in a continentwide standard

Response: Thank you for your comments.
Georgia Transmission
Corporation

Yes

MISO
Occidental Chemical
Corporation

Yes

As a Generator Owner, Occidental Chemical will only be subject to PRC-006-SERC-01
Requirement R8 and its three sub-requirements. These call for GOs to provide SERC their
generator frequency relay set points, clearing times, and maximum MW that could be separated
from the system; within 30 days of a request. R8 further qualifies the reliability need is to “facilitate
post-event analysis of frequency disturbances.”However, SERC already has the authority to gather

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 5 Comment
disturbance-related information from Generator Operators under EOP-004-1. As with many
Generator Owners, Occidental Chemical is also registered as a GOP, and would have to provide
such information in support of Regional disturbance investigations. However, even organizations
which do not support both functions would have to coordinate with each other to supply any system
event-related information requests from SERC. If this is not sufficient, MOD-010-0 and MOD-012-0
require Generator Owners to provide static and dynamic generator modeling data in accordance
with the Regional Entity’s specification. It would seem that SERC’s specification could be modified
to accommodate frequency relay data without creating any new enforceable reliability requirements.
We understand that the proposed requirements are not onerous and the data can be easily
supplied. However, Occidental Chemical is uneasy about applying a Standard related to
underfrequency Load shedding to generation. It implies a connection with other entities that does
not exist and a protective function that serves a very different purpose.

Response:
The SDT disagrees. While Attachment 1-EOP-004 NERC Disturbance Report Form requires a report to be filed in
response to an event where frequency or voltage goes “below the under-frequency or under-voltage load shed” set
points, the form does not include the requirement to report the information spelled out in requirement R7 of PRC006-SERC-01.
The MOD-010, MOD-012, and associated SERC regional criteria do not require that generator underfrequency and
overfrequency protective setpoints be provided. Inclusion of this requirement in the standard ensures that the
region receives necessary information. The SDT believes that including this requirement in the standard provides
adequate notification to entities regarding providing specific data upon request to facilitate post-event analysis of
frequency disturbances.
The SDT believes that this connection between generator underfrequency and overfrequency protection and UFLS
protection does exist. While the generator protective function may serve a very different purpose, protection of the
generating unit versus protecting the transmission system, both must be coordinated since units that trip offline
during an under frequency event remove generation which may aggravate the event.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

6. If you have any other comments that you have not already provided in the response to the prior
questions, please provide them here.

Summary Consideration:

Organization
LG&E and KU Energy

Yes or No

Question 6 Comment
In R8, LG&E and KU Energy’s GO would recommend 45 days, rather than 30 days, simply because
while a Company is performing their post-event analysis it normally takes longer than 30 days to
collect data with appropriate approvals. As an example, if an event happened in early December of
a given year, it might prove difficult to get the appropriate agreement/approvals on data to submit
within 30 days in a month that typically has personnel on holiday/vacations. Providing for a 45-day
response would minimize this possible occurrence without harming overall system reliability.

Response:
The SDT feels that 30 days is adequate for the Generator Owner to provide the information required in R8.1, R8.2
and R8.3. This information should be readily available from the GO and does not require the GO to perform a post
event analysis. In the event of an actual frequency disturbance it is imperative that SERC receives this information
in a timely manner in order to perform an event analysis within the 90 day requirement specified by NERC.
Dominion
NERC Staff Technical Review

We support the following observations made during the Quality Review:
General Observations
[A] o The standard references the SERC sub-region but it is not defined.
[B] o The SERC Region is referenced in the requirements. The RE is not normally referenced in
each of the requirements.
[C] Requirement R1: 1.1 should be a bullet since it is not a requirement.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 6 Comment
[D] Requirement R2: Is (percent of load to be shed, frequency set points, and time delays) needed
in the main requirement since they are spelled out in the sub-requirements?
[E] 2.3.1 is not a sub-requirement because it is an exclusion. Consider making it the last sentence
in 2.3 Requirement
[F] R3: Imbalance is used two times. Consider referring back to first imbalance and clarifying
second imbalance by adding ‘such’ before the second imbalance.
[G] R3 references a specific NERC standard and requirement within that standard - it is generally
best not to have a specific reference to another standard. If the referenced standard changes then
the standard making the references needs to be updated.
[H] General observation: Since the SERC standard does not replace the NERC standard and it is
noted in the Guideline and Technical Basis that both the SERC and NERC standards must be
followed to ensure full compliance does R3 have the potential for double jeopardy? Requirement
[I] R4: ‘Shall be responsible for implementing’ is passive - consider changing to ‘shall implement’.
Requirement
[J] R5: ‘Shall be responsible for implementing’ is passive - consider changing to ‘shall implement’.
Requirement
[K] R6: The requirement lists ‘which involve frequency settings, relay time delays, and changes’.
Are there settings that do not involve the above? Since the above was listed are there settings that
do not have to be changed within 18 months? The requirement reads like those are the only
settings that will need changes within 18 months. Is the intent to limit it to these parameters or are
they examples?
[L] Requirement R7: Is it clear to the PC who within SERC this requirement is referencing? Should
this be more specific about what department or area in SERC? Requirement
[M] R8: General Observation: This is the only requirement that references the Generator Owner.
The GO only has to provide information and does not have not to make any changes. Is there
another standard that provides the responsibilities of the GO other than providing information?

Response:

A. A note on subregions was added to the text box for R1 referencing the SERC Bylaws.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 6 Comment

B. The phrase “in the SERC Region” does not appear in R1 and R8, but did appear and has been deleted from R2,
C.
D.
E.
F.
G.
H.

I.
J.
K.

R3, R6, and R7. The phrase is needed in R4 and R5 since a UFLS Entity may have load in more than one Regional
Entity.
Part 1.1 was changed to a bullet.
The phrase was added to provide clarity for what is meant by “the UFLS scheme.”
Part 2.3.1 was the last sentence of 2.3 in Draft 7, but was separated into a separate part based on a
recommendation from a quality review by SERC Legal. The concern was that this exclusion distracted from the
main focus of 2.3, and caused some confusion. Part 2.3.1 was changed to a bullet to make it consistent with R1.
The word “such” was added before the second ‘imbalance.”
References to the specific requirement and the NERC standard number was removed for the requirement and
added to the text box for R3.
The SDT was concerned with possible double jeopardy and tried to avoid any such issues in the design of the
SERC standard. However, the SDT also felt strongly that more specificity was needed on what addressed the “up
to” 25% imbalance requirement in R3 of the NERC standard. By specifying the three imbalance levels that are to
be simulated, R3 of the SERC standard defines what is required in the SERC region to meet the “up to”
requirement in R3 of the NERC standard. However, R3 was revised to clarify the intent.
The phrase has been changed to “shall implement.” Other revisions were made to R4 to clarify the intent.
The phrase has been changed to “shall implement.” Other revisions were made to R5 to clarify the intent.
These three parameters generally define a UFLS scheme. Typically a UFLS Entity annually only needs to make
changes to a few UFLS relays due to load growth to ensure both the load shed per step and total load shed is
within scheme tolerances. However, if the PC makes changes to frequency settings, relay time delays, and/or
changes to the percentage of load in the scheme, it typically could require the UFLS Entities to make field
adjustments to a majority of their UFLS relays, and may require installation of addition UFLS relaying. This could
be a significant effort which would require much more time to complete than that allowed in R4 and R5.
This should not be a problem for the PC. SERC has data reporting processes which involve entity notification of
data requirements and data submittal through SERC portal forms or bulk upload templates. SERC stakeholders
currently report this same UFLS data through a SERC compliance data reporting process.

M. SERC has no other standards and no current plans to develop additional standards. While the GO has

only a data reporting requirement in this standard, it is felt that this standard is the appropriate place
to document that requirement.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 6 Comment

Duke Energy
Exelon

[A] For GOs there needs to be close integration with Standards being developed by NERC. Similar
to other Regions, SERC PRC-006-01 should be suspended until NERC Project 2007-09 and NERC
Project 2007-01 are complete. PRC-006-FRCC-01 is currently on hold in the FRCC Region with
the status "pending the completion of the NERC Reliability Standard Development Project 2007-01
"Underfrequency Load Shedding."PRC-006-MRO-01 is currently on hold in the MRO Region with
the status "suspended."PRC-006-TRE-01 is also currently on hold in the TRE Region with the
status "following the progress of the NERC UFLS SDT."Exelon suggests that the SERC SDT also
suspend progress on SERC PRC-006-01 and similarly follow the progress of NERC Projects 200709 and 2007-01. At that time SERC should reevaluate if additional Regional guidance is necessary.
[B] Consideration should be given to ensure that Planning Coordinators not be given the ability to
develop defacto NERC Requirements without due process. For example; the Planning Coordinator
will have the sole discretion to determine what an island is, determine needed remediation, and
determine the UFLS scheme in general without a process for stakeholders to formally interact.
[C] For SERC PRC-006-01 the settings should align with the pending NERC Standard PRC-006-1,
for the load shedding setting the error bandwidth is too broad and the criteria determination for an
island is not clear. As stated previously, Exelon does not see the need for Regional Standard when
a NERC Standard will likely be approved by FERC.

Response:
A. While some regions have suspended work on their regional UFLS standards, other regions (e.g. RFC, SPP, and
NPCC) are proceeding. The SDT believes that the current NERC PRC-006-1 standard is sufficiently well developed
such that moving forward with SERC Standard PRC-006-SERC-01 is beneficial, even though the NERC standard,
which was Board Approved November 10, 2010, is still in the final regulatory approval process. SERC Standard
PRC-006-SERC-01 provides additional clarity and specificity to the requirements stated in the NERC UFLS
standard that the SDT believes are necessary for effective implementation of UFLS within the SERC Region (as is
stated in the Guideline and Technical Basis item #1 of PRC-006-SERC-01). The guidance and direction provided
in SERC Standard PRC-006-SERC-01 is beneficial. With respect to the comment that “For GOs there needs to be
close coordination,” the SERC UFLS standard imposes a reporting only requirement for a limited number of
existing generator parameters.

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 6 Comment

B. The SERC UFLS standard does not give the Planning Coordinator the ability to develop defacto NERC (or SERC)
requirements. The SERC UFLS standard simply provides more specific guidance on how the Planning
Coordinator is to execute its essential responsibilities, which have been assigned by the NERC UFLS standard.
C. The NERC UFLS standard does not specify any bandwidth for the amount of load to be shed by various UFLS
entities. SERC Standard PRC-006-SERC-01 attempts to provide a reasonable margin for the amount of load to
enable for UFLS, with additional margin given to smaller UFLS entities which may have difficulty in achieving a
precise load percentage due to a limited number of loads and/or feeders. The SDT believes that the bandwidths
specified are reasonable, given the practical considerations of implementing the settings in the field. The criteria
for determining islands are addressed in the NERC PRC-006-1 standard.

South Carolina Electric and
Gas
Georgia Transmission
Corporation

1. R1 seems to have subject/verb confusion as written and the terms “when developing criteria”
suggests that the PC would only have to comply ever so often “when developing criteria”. The
measurement and VSL suggests the intent of the requirement is for each PC to “develop criteria”.
The following is suggested: R1. Each Planning Coordinator shall develop criteria for selecting
portions of the BPS that may form islands. The criteria shall: 1.1 include its SERC subregion as an
identified island 1.1.1 A Planning Coordinator may adjust island boundaries to differ from
subregional boundaries where necessary for the sole purpose of producing a contiguous
subregional island more suitable for simulation.
2. M4 identifies a specific target implementation date of “May 1 of each calendar year” which is not
identified in the requirement.
3. Should R2 identify a time qualifier to compliment M4...such as “the PC shall annually select or
develop an automatic UFLS scheme”?
4. There is circular confusion within M4 and R5. It appears that the PC will develop a UFLS
scheme on an annual basis and expect the UFLS entity to implement it. The UFLS entity could
then implement it by May 1 according to M4, or recognize it as a change from the previous year’s
scheme and implement it within 18 months according to R5. Additionally, It seems based on M4,
that the annually developed UFLS scheme target date of May 1 could come before a previously

Consideration of Comments on Regional Reliability Standard Automatic Underfrequency Load Shedding PRC-006-SERC-01

Organization

Yes or No

Question 6 Comment
“changed” UFLS scheme with an 18 month target date.

Response:
1. The requirement to develop criteria for selecting portions of the BPS that may form islands is in NERC Standard
PRC-006-1. The SERC Requirement R1 says that the criteria must include the subregion as an island. The SDT
revised R1 to provide additional clarity.
2. May 1 is the date that the implementation of the UFLS scheme will be measured each year. The SDT revised R4
and R5 to provide additional clarity.
3. No. It is not anticipated that the UFLS scheme will change annually. R2 requires the PC’s UFLS scheme to meet
certain requirements. The scheme does not have to be updated annually. The implementation of the scheme will
be checked annually as indicated by R4 and R5.
4. The PC will not annually develop a UFLS scheme. Changes to the scheme will be rare. As indicated in M4, if
scheme changes are in progress (the 18 month period), the requirements of R4 do not have to be met. A more
detailed explanation is provided in item # 4 of the Guideline and Technical Basis section located at the end of the
standard.
MISO

MISO believes that the prescriptive requirements for setting frequency set points in PRC-006SERC-001 are inconsistent with NERC Standard PRC-006-1. The NERC standard requires each
Planning Coordinator to develop a UFLS program for its area, and gives the PC substantial
discretion to devise specific frequency set points and UFLS block schemes to achieve system
condition or performance goals. PRC-006-SERC-001 R2 usurps this grant of discretion by
mandating that frequency set points be within a prescriptive range that limits not only the highest
and lowest points, but also the number and range of set point blocks that a PC can establish without
regard to unique system conditions or coordination with neighboring systems.

Response: See response to your comment on Question 2 above.
Occidental Chemical
Corporation
END OF REPORT

Individual or group. (9 Responses)
Name (6 Responses)
Organization (6 Responses)
Group Name (3 Responses)
Lead Contact (3 Responses)
Question 1 (8 Responses)
Question 1 Comments (9 Responses)
Question 2 (7 Responses)
Question 2 Comments (9 Responses)
Question 3 (8 Responses)
Question 3 Comments (9 Responses)
Question 4 (7 Responses)
Question 4 Comments (9 Responses)
Question 5 (8 Responses)
Question 5 Comments (9 Responses)
Question 6 (0 Responses)
Question 6 Comments (9 Responses)

Individual
Laura Lee
Duke Energy
Yes
No
No
No
Yes

Individual
John Bee
Exelon
Yes

No
This regional standard is not necessary for GOs due to the work that is being done under NERC
Project 2007-09, PRC-024, "Generator Performance During Frequency and Voltage Excursions," and
therefore suggest that the SERC UFLS Standard remove GOs from applicability section. It is not clear
that the criteria proposed in this standard are really more specific than the performance criteria
proposed in the NERC Standard PRC-006,"Development and Documentation of Regional UFLS
Programs," currently at the FERC. The intent of the threshold for additional Regional Standards is to
address a Regional issue. There doesn’t appear to be a particular issue to the SERC Region that is
different than the rest of the Eastern Interconnection. Changing a setpoint value that already is an
outcome of the performance criteria doesn’t necessarily provide additional specificity. For a Region to
have requirements that are not included in the continent-wide Standard is problematic, there should

be some geographic or electric justification for such a difference, otherwise the Requirements should
be incorporated into the continent-wide Standard. Simply adding a Requirement that is not in the
pending NERC Standard does not make the Regional Standard necessary. It is not clear that there is a
physical difference between the power system of the SERC Region as compared with the rest of the
Eastern Interconnection.
For GOs there needs to be close integration with Standards being developed by NERC. Similar to
other Regions, SERC PRC-006-01 should be suspended until NERC Project 2007-09 and NERC Project
2007-01 are complete. PRC-006-FRCC-01 is currently on hold in the FRCC Region with the status
"pending the completion of the NERC Reliability Standard Development Project 2007-01
"Underfrequency Load Shedding." PRC-006-MRO-01 is currently on hold in the MRO Region with the
status "suspended." PRC-006-TRE-01 is also currently on hold in the TRE Region with the status
"following the progress of the NERC UFLS SDT." Exelon suggests that the SERC SDT also suspend
progress on SERC PRC-006-01 and similarly follow the progress of NERC Projects 2007-09 and 200701. At that time SERC should reevaluate if additional Regional guidance is necessary. Consideration
should be given to ensure that Planning Coordinators not be given the ability to develop defacto NERC
Requirements without due process. For example; the Planning Coordinator will have the sole
discretion to determine what an island is, determine needed remediation, and determine the UFLS
scheme in general without a process for stakeholders to formally interact. For SERC PRC-006-01 the
settings should align with the pending NERC Standard PRC-006-1, for the load shedding setting the
error bandwidth is too broad and the criteria determination for an island is not clear. As stated
previously, Exelon does not see the need for Regional Standard when a NERC Standard will likely be
approved by FERC.
Group
LG&E and KU Energy
Brent Ingebrigtson
Yes
No
No
No
Yes
In R8, LG&E and KU Energy’s GO would recommend 45 days, rather than 30 days, simply because
while a Company is performing their post-event analysis it normally takes longer than 30 days to
collect data with appropriate approvals. As an example, if an event happened in early December of a
given year, it might prove difficult to get the appropriate agreement/approvals on data to submit
within 30 days in a month that typically has personnel on holiday/vacations. Providing for a 45-day
response would minimize this possible occurrence without harming overall system reliability.
Group
Dominion
Louis Slade
Yes
No
No
No
Yes

Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
No
No
No
Yes
The proposed standard has more specific criteria for the same requirements covered in a continentwide standard
Individual
Jason Snodgrass
Georgia Transmission Corporation
Yes
No
No
No
Yes
1. R1 seems to have subject/verb confusion as written and the terms “when developing criteria”
suggests that the PC would only have to comply ever so often “when developing criteria”. The
measurement and VSL suggests the intent of the requirement is for each PC to “develop criteria”. The
following is suggested: R1. Each Planning Coordinator shall develop criteria for selecting portions of
the BPS that may form islands. The criteria shall: 1.1 include its SERC subregion as an identified
island 1.1.1 A Planning Coordinator may adjust island boundaries to differ from subregional
boundaries where necessary for the sole purpose of producing a contiguous subregional island more
suitable for simulation. 2. M4 identifies a specific target implementation date of “May 1 of each
calendar year” which is not identified in the requirement. 3. Should R2 identify a time qualifier to
compliment M4…such as “the PC shall annually select or develop an automatic UFLS scheme”? 4.
There is circular confusion within M4 and R5. It appears that the PC will develop a UFLS scheme on an
annual basis and expect the UFLS entity to implement it. The UFLS entity could then implement it by
May 1 according to M4, or recognize it as a change from the previous year’s scheme and implement it
within 18 months according to R5. Additionally, It seems based on M4, that the annually developed
UFLS scheme target date of May 1 could come before a previously “changed” UFLS scheme with an 18
month target date.
Individual
Kelsey Colvin
MISO
MISO is concerned that PRC-006-SERC-001 R2 is too prescriptive and may not allow Planning

Coordinators the flexibility and discretion needed to ensure reliability. The Planning Coordinator is
tasked with designing the UFLS system and coordinating that system with neighboring systems. PRC006-SERC-001 R2 specifies acceptable ranges and limits in R2.3, R2.4, R2.5 and R2.6 for the UFLS
design. The standard makes no provisions to accommodate a determination by a PC that the best
performing design does not fit in with the specified set points and ranges in the standard. As noted in
the standard, the set points specified in R2 reflect historic practice, but there may be sound technical
justification to deviate from the set points scheme PRC-006-SERC-001 R2 proscribes. It is possible
that effective coordination with neighboring systems may require a different approach (e.g. entities in
MRO are investigating the reliability benefits of setting the frequency set point blocks at less than 0.2
Hz apart to create finer system control). The explicit set point requirements in R2 would prohibit
innovation/coordination of system design that deviated from standard without regard to the reliability
benefits of deviating from historic practice.

MISO believes that the prescriptive requirements for setting frequency set points in PRC-006-SERC001 are inconsistent with NERC Standard PRC-006-1. The NERC standard requires each Planning
Coordinator to develop a UFLS program for its area, and gives the PC substantial discretion to devise
specific frequency set points and UFLS block schemes to achieve system condition or performance
goals. PRC-006-SERC-001 R2 usurps this grant of discretion by mandating that frequency set points
be within a prescriptive range that limits not only the highest and lowest points, but also the number
and range of set point blocks that a PC can establish without regard to unique system conditions or
coordination with neighboring systems.
Group
NERC Standards Staff
Howard Gugel
Yes
No
No
No
Yes
We support the following observations made during the Quality Review: General Observations • The
standard references the SERC sub-region but it is not defined. • The SERC Region is referenced in the
requirements. The RE is not normally referenced in each of the requirements. Requirement R1: 1.1
should be a bullet since it is not a requirement. Requirement R2: Is (percent of load to be shed,
frequency set points, and time delays) needed in the main requirement since they are spelled out in
the sub-requirements? 2.3.1 is not a sub-requirement because it is an exclusion. Consider making it
the last sentence in 2.3 Requirement R3: Imbalance is used two times. Consider referring back to first
imbalance and clarifying second imbalance by adding ‘such’ before the second imbalance. R3
references a specific NERC standard and requirement within that standard – it is generally best not to
have a specific reference to another standard. If the referenced standard changes then the standard
making the references needs to be updated. General observation: Since the SERC standard does not
replace the NERC standard and it is noted in the Guideline and Technical Basis that both the SERC
and NERC standards must be followed to ensure full compliance does R3 have the potential for double
jeopardy? Requirement R4: ‘Shall be responsible for implementing’ is passive – consider changing to
‘shall implement’. Requirement R5: ‘Shall be responsible for implementing’ is passive – consider
changing to ‘shall implement’. Requirement R6: The requirement lists ‘which involve frequency
settings, relay time delays, and changes’. Are there settings that do not involve the above? Since the
above was listed are there settings that do not have to be changed within 18 months? The

requirement reads like those are the only settings that will need changes within 18 months. Is the
intent to limit it to these parameters or are they examples? Requirement R7: Is it clear to the PC who
within SERC this requirement is referencing? Should this be more specific about what department or
area in SERC? Requirement R8: General Observation: This is the only requirement that references the
Generator Owner. The GO only has to provide information and does not have not to make any
changes. Is there another standard that provides the responsibilities of the GO other than providing
information?
Individual
Michelle R. D'Antuono
Occidental Chemical Corporation
Yes
No
No
No
Yes
As a Generator Owner, Occidental Chemical will only be subject to PRC-006-SERC-01 Requirement R8
and its three sub-requirements. These call for GOs to provide SERC their generator frequency relay
set points, clearing times, and maximum MW that could be separated from the system; within 30
days of a request. R8 further qualifies the reliability need is to “facilitate post-event analysis of
frequency disturbances.” However, SERC already has the authority to gather disturbance-related
information from Generator Operators under EOP-004-1. As with many Generator Owners, Occidental
Chemical is also registered as a GOP, and would have to provide such information in support of
Regional disturbance investigations. However, even organizations which do not support both functions
would have to coordinate with each other to supply any system event-related information requests
from SERC. If this is not sufficient, MOD-010-0 and MOD-012-0 require Generator Owners to provide
static and dynamic generator modeling data in accordance with the Regional Entity’s specification. It
would seem that SERC’s specification could be modified to accommodate frequency relay data without
creating any new enforceable reliability requirements. We understand that the proposed requirements
are not onerous and the data can be easily supplied. However, Occidental Chemical is uneasy about
applying a Standard related to underfrequency Load shedding to generation. It implies a connection
with other entities that does not exist and a protective function that serves a very different purpose.

Requirement R8 shall become effective 12 months after the first day of the first quarter following
regulatory approval. This 12-month period is needed to allow time for Generator Owners (GO)
to collect and make an initial data filing.
Retired standards
None

SERC UFLS Std_PRC-006-SERC-01 Implementation Plan (06-15-11).docx

SERC UFLS Standard: PRC-006-SERC-01

06/15/11

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development steps completed:
1. SAR accepted by SERC Standards Committee (February 27, 2008).
2. SAR approved by EC Executive Committee (April 25, 2008).
3. SAR posted for comment (April 25, 2008 through May 27, 2008).
4. Revised SAR and response to comments approved by EC Executive Committee (June
16, 2008).
5. SDT appointed on (June 19, 2008).
6. Draft 1 of proposed standard posted (September 19, 2008 through October 20, 2008).
7. Draft 2 of proposed standard posted (November 21, 2008 through December 22, 2008).
8. Draft 3 of proposed standard posted for information (February 9, 2009).
9. Draft 3a of proposed standard posted (September 15, 2009 through October 15, 2009).
10. Draft 4 of proposed standard posted for a 15-day pre-ballot review (October 27, 2009
through November 10, 2009).
11. Draft 4 of proposed standard ballot open (November 13 through 23, 2009). Ballot made
quorum with 92.9% votes (minimum of 66.7%). Approval of 48.5% (minimum of 66.7% of
weighted sector votes required). Standard was not approved.
12. Draft 5 of proposed standard posted (September 21, 2010 through October 21, 2010).
13. Draft 6 of proposed standard posted for a 15-day pre-ballot review (November 22, 2010
through December 8, 2010).
14. Draft 6 ballot open December 9 through 20, 2010: Quorum count of 65.7% (minimum of
66.7% of ballot pool votes required, 23 of a possible 35 votes received, did not make
quorum). Approval vote of 61.1% (minimum of 66.7% of weighted sector votes required,
standard would not have been approved).
15. Draft 7 of proposed standard posted (February 22 through March 24, 2011).
16. Draft 8 of proposed standard posted for pre-ballot review (April 29 through May 23,
2011).
17. Draft 8 ballot open May 24 through June 6, 2011: Quorum count of 91.2% (minimum of
66.7% of ballot pool votes required) 31 of a possible 34 votes received, made quorum.
Approval vote of 77.2% (minimum of 66.7% of weighted sector votes required). Standard
was approved.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

Page 1 of 19

SERC UFLS Standard: PRC-006-SERC-01

06/15/11

Proposed action plan and description of current draft:
This is Draft 8 of the proposed standard which received Ballot Pool approval on June 6, 2011.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Request NERC to review and post for comments.

June 22, 2011

2. Resolve comments from NERC posting.

August 26, 2011

3. SERC Board Executive Committee adopts standard.

September 21, 2011

4. Submit request to NERC for approval and filing with FERC.

September 29, 2011

5. NERC files standard with FERC.

To be determined.

Effective dates:
Requirement R1 shall become effective 12 months after the first day of the first quarter following
regulatory approval, but no sooner than 12 months following regulatory approval of NERC PRC006-1. This 12-month period is consistent with the effective date of R2 of PRC-006-1.
Requirement R2 shall become effective 12 months after the first day of the first quarter following
regulatory approval. This 12-month period is needed to allow time for entities to ensure a
minimum time delay of six cycles on existing UFLS relays as specified in part 2.6.
Requirements R3 shall become effective 18 months after the first day of the first quarter
following regulatory approval. This additional six-month period is needed to allow time to
perform and coordinate studies necessary to assess the overall effectiveness of the UFLS
schemes in the SERC Region.
Requirements R4, R5, and R6 shall become effective 30 months after the first day of the first
quarter following regulatory approval. This additional 18 months is needed to allow time for any
necessary changes to be made to the existing UFLS schemes in the SERC Region.
Requirement R7 shall become effective six months following the effective date of R8 of the
NERC standard PRC-006-1, but no sooner than one year following the first day of the first
calendar quarter after applicable regulatory approval of PRC-006-SERC-1. R8 of the NERC
standard requires each UFLS entity to provide UFLS data to the Planning Coordinator (PC). R7
of the SERC standard requires the PC to provide this data to SERC.
Requirement R8 shall become effective 12 months after the first day of the first quarter following
regulatory approval. This 12-month period is needed to allow time for Generator Owners to
collect and make an initial data filing.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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SERC UFLS Standard: PRC-006-SERC-01

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Revision History
Version

Date

Action

Change Tracking
st

Draft 1

September 19 2008
Posted for 1 comment period
thru October 20, 2008

Draft 2

November 21, 2008
thru December 22,
2008

Posted for 2nd comment period

Revised to address
comments received on Draft
1 and to include measures
and compliance sections

Draft 3

February 9, 2009

Posted for information

Revised to address
comments received on Draft
2

Draft 3a

September 15, 2009
Posted for 3rd comment period
thru October 15, 2009

Revised to make consistent
with Draft 2 of NERC
continent-wide standard

Draft 4

October 27, 2009 thru Posted for pre-ballot review
November 10, 2009

Revised to address
comments received on Draft
3a

Draft 5

September 21, 2010
Posted for 30-day comment Revised to address
thru October 21, 2010 period
comments received on Draft
4 ballot and to make
consistent with latest draft
of NERC continent-wide
standard

Draft 6

November 23, 2010
thru December 8,
2010

Posted for pre-ballot review

Draft 7

February 22 thru
March 24, 2011

Posted for 30-day comment Revised to address
period
comments received on
ballot of Draft 6

Draft 8

April 29, 2011 thru
May 23, 2011

Posted for pre-ballot review

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

Initial version

Revised to address
comments received on Draft
5

Revised to address
comments received on Draft
7

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Definitions of terms used in standard
This section includes all newly-defined or revised terms used in the proposed standard. Terms
already defined in the NERC Reliability Standards Glossary of Terms are not repeated here.
New or revised definitions listed below become approved when the proposed standard is
approved. When the standard becomes effective, these defined terms will be removed from the
individual standard and added to the Glossary.
There are no new or revised definitions proposed in this standard revision.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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SERC UFLS Standard: PRC-006-SERC-01

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Introduction
1.

Title: Automatic Underfrequency Load Shedding Requirements

Number: PRC-006-SERC–01

Background
The SERC UFLS Standard: PRC-006-SERC-1 (“SERC UFLS Standard”) was
developed to provide regional UFLS requirements to entities in SERC. UFLS
requirements have been in place at a continent-wide level and within SERC for many
years prior to implementation of federally mandated reliability compliance standards in
2007.
When reliability standards were implemented in 2007, the Federal Energy Regulatory
Commission (“FERC”), which is the government body with regulatory responsibility for
electric reliability, issued FERC Order 693, recognizing 83 NERC Reliability Standards
as enforceable by FERC and applicable to users, owners, and operators of the bulk
power system (BPS). FERC did not approve the NERC UFLS standard, PRC-006-0 in
Order 693. FERC’s reason for not approving PRC-006-0 was that it recognized PRC006-0 as a “fill-in the blank standard,” and regional procedures associated with the
standard were not submitted along with the standard. FERC’s ruling in Order 693
required Regional Entities to provide the regional requirements necessary for
completing the UFLS standard.
In 2008, SERC commenced work on PRC-006-SERC-01. NERC also began work on
revising PRC-006-0 at a continent-wide level. The SERC standard has been developed
to be consistent with the NERC UFLS standard.
PRC-006-1 clearly defines the roles and responsibilities of parties to whom the standard
applies. The standard identifies the Planning Coordinator (“PC”) as the entity
responsible for developing UFLS schemes within their PC area. The regional standard
adds specificity not contained in the NERC standard for development and
implementation of a UFLS scheme in the SERC Region that effectively mitigates the
consequences of an underfrequency event.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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SERC UFLS Standard: PRC-006-SERC-01

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Requirements and Measures
R1. Each Planning Coordinator shall include its SERC subregion as an identified island
when developing criteria for selecting portions of the BPS that may form islands.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]
1.1

A Planning Coordinator may adjust island boundaries to differ from subregional
boundaries where necessary for the sole purpose of producing a contiguous
subregional island more suitable for simulation.

M1. Each Planning Coordinator shall have evidence such as a methodology,
procedure, report, or other documentation indicating that its criteria included
selection of its SERC subregion(s) as an island per Requirement R1.
Studying the Region as an island is required by the NERC standard. Most regions
have only one or a few different UFLS schemes. Where there is more than one
scheme, studying this island demonstrates that the schemes are coordinated and
performing adequately. Because there are so many different UFLS schemes in SERC
(18 different schemes were represented in the 2007 SERC UFLS study), the SDT
believes that applying the schemes to each subregion as an island is a necessary
additional test of the coordination of the various UFLS schemes. Without this
additional test, a poorly performing scheme may be masked by the large number of
good performing schemes in the Region. A subregion island study, which would
have a smaller number of schemes, would be more likely to uncover the poorly
performing scheme and therefore get it fixed. This approach will result in a much
better overall performance of the UFLS programs in SERC. The SDT recognized that
there may be simulation problems due to opening the ties to utilities outside the
subregion. Therefore, the subregion island boundaries are allowed to be adjusted to
produce an island more suitable for simulation.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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SERC UFLS Standard: PRC-006-SERC-01

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R2. Each Planning Coordinator in the SERC Region shall select or develop an automatic
UFLS scheme (percent of load to be shed, frequency set points, and time delays) for
implementation by UFLS entities within its area that meets the following minimum
requirements: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]
2.1. Have the capability of shedding at least 30 percent of the Peak Demand (MW)
served from the Planning Coordinator’s transmission system.
2.2. Shed load with a minimum of three frequency set points.
2.3. The highest frequency set point for relays used to arrest frequency decline shall
be no lower than 59.3 Hz and not higher than 59.5 Hz.
2.3.1 This does not apply to UFLS relays with time delay of one second or longer
and a higher frequency setpoint applied to prevent the frequency from
stalling at less than 60 Hz when recovering from an underfrequency event.
2.4. The lowest frequency set point shall be no lower than 58.4 Hz.
2.5. The difference between frequency set points shall be at least 0.2 Hz but no
greater than 0.5 Hz.
2.6. Time delay (from frequency reaching the set point to the trip signal) shall be at
least six cycles.

M2. Each Planning Coordinator shall have evidence such as reports or other
documentation that the UFLS scheme for its area meets the design requirements
specified in Requirement R2.

These requirements for the UFLS schemes in SERC have been in place for many years
(except 2.6). The SDT believes that these requirements are still needed to ensure
consistency for the various schemes which are used in SERC. Part 2.6 is designed to
prevent spurious operations due to transient frequency swings.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R3. Each Planning Coordinator in the SERC Region shall conduct simulations of its UFLS
scheme for an imbalance between load and generation of 13%, 22%, and 25% for all
identified island(s) where imbalance equals [(load minus actual generation output) /
load]. These simulation requirements apply to the UFLS assessments specified in R4 of
the NERC UFLS standard PRC-006-1. [Violation Risk Factor: High] [Time Horizon:
Long-term Planning ]
M3. Each Planning Coordinator shall have evidence such as reports or other
documentation that it performed the simulations of its UFLS scheme as required
in Requirement R3.

The NERC standard requires that schemes meet performance requirements for
generation/load imbalances of up to 25%. This requirement defines specific
imbalances that are to be studied within SERC. The 13% and 22% levels were
determined from simulations of the worst case frequency overshoot for the
UFLS schemes in SERC.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R4. Each UFLS entity that has a total load of 100 MW or greater in a Planning Coordinator
area in the SERC Region shall be responsible for implementing the UFLS scheme
developed by their Planning Coordinator. UFLS entities may coordinate with other UFLS
entities to implement the UFLS scheme developed by the Planning Coordinator
responsible for their collective systems. The UFLS scheme shall meet the following
requirements. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning ]

4.1. The percent of load shedding to be implemented shall be based on the actual or
estimated distribution substation or feeder demand (including losses) of the UFLS
entities at the time coincident with the previous year actual Peak Demand.
4. 2. The amount of load in each load shedding step shall be within -1.0 and +3.0 of
the percentage specified by the Planning Coordinator (for example, if the specified
percentage step load shed is 12%, the allowable range is 11 to 15%).
4. 3. The amount of total UFLS load of all steps combined shall be within -1.0 and +5.0
of the percentage specified by the Planning Coordinator for the total UFLS load in
the UFLS scheme.

M4. Each UFLS entity that has a total load of 100 MW or greater in a Planning
Coordinator area in the SERC Region shall have evidence such as reports or
other documentation demonstrating that its implementation of the UFLS scheme
on May 1 of each calendar year meets the requirements of Requirement R4
unless scheme changes per Requirement R6 are in process.

The SDT believes it is necessary to put a requirement on how well the UFLS scheme is
implemented. This requirement specifies how close the actual load shedding
amounts must be to the percentage of load called for in the scheme. A 4 percentage
point range is allowed for each individual step, but the allowed range for all steps
combined is 6 percentage points.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R5. Each UFLS entity that has a total load less than 100 MW in a Planning Coordinator area
in the SERC Region shall be responsible for implementing the UFLS scheme developed
by their Planning Coordinator, but shall not be required to have more than one UFLS
step. UFLS entities may coordinate with other UFLS entities to implement the UFLS
scheme developed by the Planning Coordinator responsible for their collective systems.
The UFLS scheme shall meet the following requirements. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning ]
.
5.1. The percent of load shedding to be implemented shall be based on the actual or
estimated distribution substation or feeder demand (including losses) of the UFLS
entities at the time coincident with the previous year actual Peak Demand.
5.2. The amount of total UFLS load shall be within ± 5.0 of the percentage specified by
the Planning Coordinator for the total UFLS load in the UFLS scheme.

M5. Each UFLS entity that has a total load less than 100 MW in a Planning
Coordinator area in the SERC Region shall have evidence such as reports or
other documentation demonstrating that its implementation of the UFLS scheme
on May 1 of each calendar year meets the requirements of Requirement R5
unless scheme changes per Requirement R6 are in process.

The SDT believes it is necessary to put a requirement on how well the UFLS scheme is
implemented. This requirement specifies how close the actual load shedding
amounts must be to the percentage of load called for in the scheme. The SDT
recognizes that UFLS entities with a load of less than 100 MW may have difficulty in
implementing more than one UFLS step and in meeting a tight tolerance. The basis of
the 100 MW comes from typical feeder load dropped by UFLS relays, and the use of a
100 MW threshold in other regional UFLS standards.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R6. Each UFLS entity in the SERC Region shall implement changes to the UFLS scheme
which involve frequency settings, relay time delays, or changes to the percentage of
load in the scheme within 18 months of notification by the Planning Coordinator.
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]

M6. Each UFLS entity shall have evidence such as reports or other documentation
demonstrating that it has made the appropriate scheme changes within 18 months
per Requirement R6.

The SDT believes it is necessary to put a requirement on how quickly changes to the
scheme should be made. This requirement specifies that changes must be made
within 18 months of notification by the PC. The 18 month interval was chosen to give
a reasonable amount of time for making changes in the field. All of the SERC region
has existing UFLS schemes which, based on periodic simulations, have provided
reliable protection for years. Events which result in islanding and an activation of the
UFLS schemes are extremely rare. Therefore, the SDT does not believe that changes
to an existing UFLS scheme will be needed in less than 18 months. However, if a PC
desires that changes to the UFLS scheme be made faster than that, then the PC may
request the implementation to be done sooner than 18 months. The UFLS entity may
oblige but will not be required to do so.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R7. Each Planning Coordinator in the SERC Region shall provide the following information
to SERC according to the schedule specified by SERC. [Violation Risk Factor: Lower]
[Time Horizon: Long-term Planning ]
7.1. Underfrequency trip set points (Hz)
7.2. Total clearing time associated with each set point (sec). This includes the time
from when frequency reaches the set point and ends when the breaker opens.
7.3. Amount of previous year actual or estimated load associated with each set point,
both in percent and in MW. The percentage and the Load demand (MW) shall be
based on the time coincident with the previous year actual Peak Demand.

M7. Each Planning Coordinator shall have evidence such as reports or other
documentation that data specified in Requirement R7 was provided to SERC in
accordance with the schedule.

The NERC standard requires that a UFLS database be maintained by the Planning
Coordinator. This requirement specifies what data must be reported to SERC. A
SERC UFLS database is needed to facilitate data sharing across the SERC Region,
with other regions, and with NERC.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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R8. Each Generator Owner shall provide the following information within 30 days of a
request by SERC to facilitate post-event analysis of frequency disturbances. [Violation
Risk Factor: Lower] [Time Horizon: Long-term Planning ]
8.1. Generator protection automatic underfrequency and overfrequency trip set points
(Hz).
8.2. Total clearing time associated with each set point (sec). This is defined as the
time that begins when frequency reaches the set point and ends when the
breaker opens. If inverse time underfrequency relays are used, provide the total
clearing time at 59.0, 58.5, 58.0, and 57.0 Hz.
8.3. Maximum generator net MW that could be tripped automatically due to an
underfrequency or overfrequency condition.

M8. Each Generator Owner shall have evidence such as reports or other
documentation that data specified in Requirement R8 was provided to SERC as
requested.

The SDT believes that generator over and under frequency tripping data is needed to
supplement the UFLS data provided by the Planning Coordinator for post‐event
analysis of frequency disturbances. This requirement states what data must be
reported to SERC by the Generator Owners.
Since the inverse time curve cannot easily be placed into the SERC database, four
clearing times based on data from the curve are requested. These clearing times are
intended to cover a range of frequencies needed for event replication as well as
provide information about generators that trip at a higher frequency than is allowed
by the NERC standard.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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SERC UFLS Standard: PRC-006-SERC-01

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Compliance
Compliance enforcement authority
SERC Reliability Corporation
Compliance monitoring and assessment process
 Compliance Audit


Self-Certification



Spot Checking



Compliance Violation Investigation



Self-Reporting



Complaint

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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Time Horizons, Violation Risk Factors, and Violation Severity Levels
Table 1
R#
R1

Time
Horizon
Long-term
Planning

Medium

Long-term
Planning

Medium

Long-term
Planning

Violation Severity Level

VRF
Lower

Moderate

High

Severe

N/A

The Planning
Coordinator did not
have evidence that its
criteria included
selection of its SERC
subregion(s) as an
island, with or without
adjusted boundaries.

The Planning
Coordinator's scheme
did not meet one of the
UFLS system design
requirements identified
in 2.2 through 2.6

The Planning
Coordinator's scheme
did not meet two of the
UFLS system design
requirements identified
in 2.2 through 2.6.

The Planning
Coordinator's scheme
did not meet three of
the UFLS system
design requirements
identified in 2.2 through
2.6.

The Planning
Coordinator's scheme
did not meet 2.1

N/A

The Planning
Coordinator failed to
conduct one of the
required simulations of
its UFLS scheme.

N/A

The Planning
Coordinator failed to
conduct two of the
required simulations of
its UFLS scheme.

The UFLS entity’s
implemented UFLS
scheme had one load
shedding step outside
the range specified in 4.
2.

The UFLS entity’s
implemented UFLS
scheme had two load
shedding steps outside
the range specified in 4.
2.

The UFLS entity’s
implemented UFLS
scheme had three or
more load shedding
steps outside the range
specified in 4.2.

High

Operations
Planning
Medium

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

OR
Four or more of the
UFLS system design
requirements identified
in 2.2 through 2.6.

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Table 1
R#

Time
Horizon

Violation Severity Level

VRF
Lower

Operations
Planning
Medium

Long-term
Planning

Medium

Moderate

High

Severe

AND

The UFLS entity's
implemented UFLS
scheme had a total load
outside the range
specified in 4.3.

N/A

The UFLS entity's
implemented UFLS
scheme had a total load
outside the range
specified in 5.2.

The UFLS entity
implemented required
scheme changes but
made them 1 to 30
days after the
scheduled date.

The UFLS entity
implemented required
scheme changes but
made them 31 to 40
days after the
scheduled date.

The UFLS entity
implemented required
scheme changes but
made them 41 to 50
days after the
scheduled date.

The UFLS entity
implemented required
scheme changes but
made them more than
50 days after the
scheduled date
OR
The UFLS entity failed
to implement the
required scheme
changes.

Long-term
Planning

Lower

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

The Planning
Coordinator provided
the data required in R6
to SERC 1 to 10 days
after the scheduled
submittal date.

The Planning
Coordinator provided
the data required in R6
to SERC 11 to 20 days
after the scheduled
submittal date.

The Planning
Coordinator provided
the data required in R6
to SERC 21 to 30 days
after the scheduled
submittal date.

The Planning
Coordinator provided
the data required in R6
to SERC more than 30
days after the
scheduled submittal
date.

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SERC UFLS Standard: PRC-006-SERC-01

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Table 1
R#

Time
Horizon

Violation Severity Level

VRF
Lower

Moderate

High

Severe

The Planning
Coordinator did not
provide to SERC one
piece of information
listed in R7.
The Generator Owner
provided the data
required in R7 to SERC
11 to 20 days after the
requested submittal
date.

The Planning
Coordinator did not
provide to SERC two
pieces of information
listed in R7.
The Generator Owner
provided the data
required in R6 to SERC
21 to 30 days after the
requested submittal
date.

The Planning
Coordinator did not
provide to SERC any of
the information listed in
R7.
The Generator Owner
provided the data
required in R7 to SERC
more than 30 days after
the requested submittal
date.

Long-term
Planning

Lower

The Generator Owner
provided the data
required in R7 to SERC
1 to 10 days after the
requested submittal
date.

The Generator Owner
The Generator Owner
The Generator Owner
did not provide to SERC did not provide to SERC did not provide to SERC
one piece of information
two pieces of
any of the information
listed in R8.
information listed in R8.
listed in R8.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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Administrative Procedure
Regional Variances
None

Interpretations
None

Guideline and Technical Basis
1. Existing UFLS schemes
Each Planning Coordinator should consider the existing UFLS programs which are in place
and should consider input from the UFLS entities in developing the UFLS scheme.
2. Basis for SERC standard requirements
SERC Standard PRC-006-SERC-01 is not a stand-alone standard, but was written to be
followed in conjunction with NERC Standard PRC-006-1. The primary focus of SERC
Standard PRC-006-SERC-01 was to provide region-specific requirements for the
implementation of the higher tier NERC standard requirements with the goals of a) adding
clarity and b) providing for consistency and a coordinated UFLS scheme for the SERC
region as a whole. Generally speaking, requirements already in the NERC standard were
not repeated in the SERC standard. Therefore, both the NERC and SERC standards must
be followed to ensure full compliance.
3. Basis for applying a percentage load shedding value to Forecast Load versus Actual
Load
The Planning Coordinator will develop a UFLS scheme to meet the performance
requirements of NERC Standard PRC-006-1 Requirement R3 and SERC Standard PRC006-SERC-01 Requirement R2. This development will result in certain percentages of load
for each UFLS entity in the Planning Coordinator’s area for which automatic under frequency
load shedding must be implemented. The Planning Coordinator develops these percentages
based on forecast peak load demand. However, the UFLS entity implements these
percentages based on the previous year’s actual peak demand. Applying the same
percentage to these different base values was intentional to ensure that both the Planning
Coordinator and UFLS entities had a clear, measurable value to use in performing their
respective roles in meeting the standard. Planning Coordinators typically use forecast
demands in their work. Whereas the previous year’s actual (or estimated) demand is
typically more available to UFLS entities. Additionally, the use of percentages based on
these different base values tends to minimize the error due to the time lag between design
and actual field implementation. Since a percentage is provided by the Planning Coordinator
to the UFLS entities, any differences between the design values (i.e., forecast load) and the
implemented values (i.e., previous year’s actual) would naturally tend to match up
reasonably well. For example, if the total planning area load in MW for which UFLS was
installed during the time of implementation was slightly higher or lower than the MW value
used in the design by the Planning Coordinator, multiplying by the specified percentage
would result in an implemented load shedding scheme that also had a reasonably similar
higher or lower MW value.
Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

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4. Basis for May 1 and 18 month time frames
Each UFLS entity must annually review that the amount of UFLS load shedding
implemented is within a certain tolerance as specified by SERC Standard PRC-006-SERC01 Requirement R4 or Requirement R5 by May 1 of the current year. May 1 was chosen to
allow sufficient time after the previous year’s peak occurred to make adjustments in the field
to the implementation if necessary to meet the tolerances specified in Requirement R4 or
Requirement R5. Therefore, the May 1 date applies only to implementation of the existing
percentages of load shedding specified by the Planning Coordinator. On the other hand, the
18-month time frame specified in PRC-006-SERC-01 Requirement R6 is intended to allow
sufficient budgeting, procurement, and installation time for additional equipment, or for
significant setting changes to existing equipment necessary to meet a revised load shedding
scheme design that has been specified by the Planning Coordinator. During this 18-month
transition period, the May 1 measurement of R4 or Requirement R5 would not apply.
5. Basis for smaller entity threshold of 100 MW
Most distribution substations have transformers rated in the range of 10 to 40 MVA. Usually
most transformers would serve 1 to 4 feeders and each feeder will normally carry between 8
and 10 MVA. In general, assuming that each feeder would carry 10 MW, an entity with a
load slightly greater than 100 MW would have at least 10 feeders available. For a program
with three 10 % steps, only 3 feeders would be required to have under frequency load shed
capabilities. The 100 MW threshold seems to provide adequate flexibility for implementing
load shedding in three steps for entities slightly greater than 100 MW.

Ballot Pool Approved: June 6, 2011
Effective Date: XX/XX/XX

Page 19 of 19

Unofficial Comment Form for Regional Reliability Standard
PRC-006-SERC-01
Please DO NOT use this form. Please use the electronic form located at the link below to
submit comments on the Regional Reliability Standard Automatic Underfrequency Load
Shedding PRC-006-SERC-01. Comments must be submitted by August 15, 2011. If
you have questions please contact Howard Gugel at howard.gugel@nerc.net or Barb Nutter
at barbara.nutter@nerc.net.
http://www.nerc.com/filez/regional_standards/regional_reliability_standards_under_develo
pment.html
Background Information
A regional reliability standard shall be: (1) a regional reliability standard that is more
stringent than the continent-wide reliability standard, including a regional standard that
addresses matters that the continent-wide reliability standard does not; or (2) a regional
reliability standard that is necessitated by a physical difference in the bulk power system.
Regional reliability standards shall provide for as much uniformity as possible with reliability
standards across the interconnected bulk power system of the North American continent.
Regional reliability standards, when approved by FERC and applicable authorities in Mexico
and Canada shall be made part of the body of NERC reliability standards, and shall be
enforced upon all applicable bulk power system owners, operators, and users within the
applicable area, regardless of membership in the region.
PRC-006-SERC-1 was developed to provide regional UFLS requirements to entities in SERC.
UFLS requirements have been in place at a continent-wide level and within SERC for many
years prior to implementation of federally mandated reliability compliance standards in 2007.
Each SERC Regional Reliability Standard shall enable or support one or more of the NERC
reliability principles, thereby ensuring that each standard serves a purpose in support of the
reliability of the regional bulk electric system. Each of those standards shall also be
consistent with all of the NERC reliability principles, thereby ensuring that no standard
undermines reliability through an unintended consequence. The NERC reliability principles
supported by this standard are the following:
•

Reliability Principle 1 — Interconnected bulk electric systems shall be planned and
operated in a coordinated manner to perform reliably under normal and abnormal
conditions as defined in the NERC Standards.

•

Reliability Principle 2 — The frequency and voltage of interconnected bulk electric
systems shall be controlled within defined limits through the balancing of real and
reactive power supply and demand.

•

Reliability Principle 3 — Information necessary for the planning and operation of
interconnected bulk power systems shall be made available to those entities
responsible for planning and operating the systems reliably.

The proposed SERC Regional Reliability Standard is not inconsistent with, or less stringent
than established NERC Reliability Standards. Once approved by the appropriate authorities,

Unofficial Comment Form: PRC-006-SERC-01
the SERC Regional Reliability Standard obligates the SERC to monitor and enforce
compliance, apply sanctions, if any, consistent with any regional agreements and the NERC
rules.
The SERC PRC-006-SERC-01 standard contains eight main requirements for applicable
entities within the SERC geographic area. The standard contains the following:
Requirement 1 Each Planning Coordinator shall include its SERC subregion as an
identified island when developing criteria for selecting portions of the BPS that may
form islands.
Requirement 2 Each Planning Coordinator in the SERC Region shall select or develop
an automatic UFLS scheme (percent of load to be shed, frequency set points, and
time delays) for implementation by UFLS entities within its area that meets the
following minimum requirements.
Requirement 3 Each Planning Coordinator in the SERC Region shall conduct
simulations of its UFLS scheme for an imbalance between load and generation of
13%, 22%, and 25% for all identified island(s) where imbalance equals [(load minus
actual generation output) / load]. These simulation requirements apply to the UFLS
assessments specified in R4 of the NERC UFLS standard PRC-006-1.
Requirement 4 Each UFLS entity that has a total load of 100 MW or greater in a
Planning Coordinator area in the SERC Region shall be responsible for implementing
the UFLS scheme developed by their Planning Coordinator. UFLS entities may
coordinate with other UFLS entities to implement the UFLS scheme developed by the
Planning Coordinator responsible for their collective systems. The UFLS scheme shall
meet the following requirements.
Requirement 5 Each UFLS entity that has a total load less than 100 MW in a
Planning Coordinator area in the SERC Region shall be responsible for implementing
the UFLS scheme developed by their Planning Coordinator, but shall not be required
to have more than one UFLS step. UFLS entities may coordinate with other UFLS
entities to implement the UFLS scheme developed by the Planning Coordinator
responsible for their collective systems. The UFLS scheme shall meet the following
requirements.
Requirement 6 Each UFLS entity in the SERC Region shall implement changes to the
UFLS scheme which involve frequency settings, relay time delays, or changes to the
percentage of load in the scheme within 18 months of notification by the Planning
Coordinator.
Requirement 7 Each Planning Coordinator in the SERC Region shall provide the
following information to SERC according to the schedule specified by SERC.
Requirement 8 Each Generator Owner shall provide the following information within
30 days of a request by SERC to facilitate post-event analysis of frequency
disturbances.
The approval process for a regional reliability standard requires NERC to publicly notice and
request comment on the proposed standard. Comments shall be permitted only on the
following criteria (technical aspects of the standard are vetted through the regional
standards development process):

Unofficial Comment Form: PRC-006-SERC-01
Unfair or Closed Process — The regional reliability standard was not developed in
a fair and open process that provided an opportunity for all interested parties to
participate. Although a NERC-approved regional reliability standards development
procedure shall be presumed to be fair and open, objections could be raised
regarding the implementation of the procedure.
Adverse Reliability or Commercial Impact on Other Interconnections — The
regional reliability standard would have a significant adverse impact on reliability or
commerce in other interconnections.
Deficient Standard — The regional reliability standard fails to provide a level of
reliability of the bulk power system such that the regional reliability standard would
be likely to cause a serious and substantial threat to public health, safety, welfare, or
national security.
Adverse Impact on Competitive Markets within the Interconnection — The
regional reliability standard would create a serious and substantial burden on
competitive markets within the interconnection that is not necessary for reliability.

1. Was the proposed standard developed in a fair and open process, using the
associated Regional Reliability Standards Development Procedure?
Yes
No
Comments:
2. Does the proposed standard pose an adverse impact to reliability or commerce
in a neighboring region or interconnection?
Yes
No
Comments:
3. Does the proposed standard pose a serious and substantial threat to public
health, safety, welfare, or national security?
Yes
No
Comments:
4. Does the proposed standard pose a serious and substantial burden on
competitive markets within the interconnection that is not necessary for
reliability?
Yes
No
Comments:
5. Does the proposed regional reliability standard meet at least one of the
following criteria?

Unofficial Comment Form: PRC-006-SERC-01

The proposed standard has more specific criteria for the same requirements
covered in a continent-wide standard

The proposed standard has requirements that are not included in the
corresponding continent-wide reliability standard

The proposed regional difference is necessitated by a physical difference in
the bulk power system.
Yes
No

Comments:
6. If you have any other comments that you have not already provided in the
response to the prior questions, please provide them here.

Regional Reliability Standards Announcement
Comment Period Open for PRC-006-SERC-01
June 29-August 15, 2011
Now available at:
http://www.nerc.com/filez/regional_standards/regional_reliability_standards_under_development.html
Proposed Standard for the SERC Reliability Corporation (SERC)
SERC has requested NERC to post regional reliability standard PRC-006-SERC-01 — Automatic Underfrequency Load
Shedding for a 45-day industry review as permitted by the NERC Rules of Procedure.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic form, please
contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment form is posted on the
regional standards development page:
http://www.nerc.com/filez/regional_standards/regional_reliability_standards_under_development.html
Background
The SERC UFLS Standard: PRC-006-SERC-1 (“SERC UFLS Standard”) was developed to provide regional UFLS
requirements to entities in SERC. UFLS requirements have been in place at a continent-wide level and within SERC for
many years prior to implementation of federally mandated reliability compliance standards in 2007.
When reliability standards were implemented in 2007, the Federal Energy Regulatory Commission (“FERC”), which is
the government body with regulatory responsibility for electric reliability, issued FERC Order 693, recognizing 83 NERC
Reliability Standards as enforceable by FERC and applicable to users, owners, and operators of the bulk power system
(BPS). FERC did not approve the NERC UFLS standard, PRC-006-0 in Order 693. FERC’s reason for not approving
PRC-006-0 was that it recognized PRC-006-0 as a “fill-in the blank standard,” and regional procedures associated with
the standard were not submitted along with the standard. FERC’s ruling in Order 693 required Regional Entities to
provide the regional requirements necessary for completing the UFLS standard.
In 2008, SERC commenced work on PRC-006-SERC-01. NERC also began work on revising PRC-006-0 at a continentwide level. The SERC standard has been developed to be consistent with the NERC UFLS standard.
PRC-006-1 clearly defines the roles and responsibilities of parties to whom the standard applies. The standard identifies
the Planning Coordinator (“PC”) as the entity responsible for developing UFLS schemes within their PC area. The
regional standard adds specificity not contained in the NERC standard for development and implementation of a UFLS
scheme in the SERC Region that effectively mitigates the consequences of an underfrequency event.
Regional Reliability Standards Development Process
Section 300 of the Rules of Procedure for the Electric Reliability Organization governs the regional reliability standards
development process. The success of the NERC standards development process depends on stakeholder participation.
We extend our thanks to all those who participate.

For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net or at 404.446.2573

Exhibit D
Standard Drafting Team Roster

SERC UFLS Standard Drafting Team Roster
(September 19, 2011)
Member

Affiliation / Job Title

Rick Foster

Ameren Services Company
Consulting Engineer

Venkat (Sharma)
Kolluri

Entergy
Manager, Transmission Planning

Greg Davis

Georgia Transmission Corporation
Protection & Controls Engineer

Ernesto Paon

Municipal Electric Authority of Georgia
Manager Protection & Control & Testing

John O'Connor

Progress Energy Carolinas
Principal Engineer

Bob Jones, Chair

Southern Company Services, Inc. –
Transmission
Planning Manager - Stability

Jonathan Glidewell

Southern Company Services, Inc. –
Transmission
Engineer, SR

Tom Cain

Tennessee Valley Authority
Electrical Engineer

Contact Information
370 S. Main St
MC E-15
Decatur, IL 62526
217-424-6716
rfoster2@ameren.com
639 Loyola Avenue
L-ENT-17A
New Orleans, LA 70113
504-576-4045
vkollur@entergy.com
2100 East Exchange Place
Tucker, GA 30084
770-270-7406
greg.davis@gatrans.com
1470 Riveredge Parkway
NW
Atlanta, GA 30328-4686
(770) 563-8195
epaon@meagpower.org
P.O. Box 1981
Mail Stop TPP-17
Raleigh, NC 27602-1981
(919) 546-2037
john.oconnor@pgnmail.com
600 North 18th Street
P.O. Box 2641
Birmingham, AL 35203-2206
205-257-6148
rajones@southernco.com
600 North 18th Street
P.O. Box 2641
Birmingham, AL 35203-2206
205-257-7622
jdglidew@southernco.com
1101 Market Street
Mail Stop MR 5G - C
Chattanooga, TN 37402
(423) 751-6828
stcain@tva.gov

Member

Affiliation / Job Title

Pat Huntley, SERC SERC Reliability Corporation
staff support
Manager, Reliability Standards

Andrew Fusco
(Resigned from
SDT on October 4,
2010)
Anthony Williams
(Resigned from
SDT on August 5,
2009)

September 19, 2011

ElectriCities of North Carolina, Inc.
Manager, Planning

Duke Energy Carolinas
Senior Engineer

Page 2

Contact Information
2815 Coliseum Centre Drive
Suite 500
Charlotte, NC 28217
(704) 940-8228
phuntley@serc1.org
1427 Meadow Wood Blvd.
Raleigh, NC 27604
919-760-6219
afusco@electricities.org
400 South Tryon Street
Mail Code: ST11F
Charlotte, NC 28202
(704) 382-8310
Anthony.Williams@dukeenergy.com

SERC UFLS Standard Drafting Team Biographies

Rick Foster: Rick has a MSEE from University of Missouri (Rolla Campus) and an MBA from
Illinois State University. He is licensed as a Professional Engineer in the State of Illinois. He
worked for Illinois Power Company in Decatur, Illinois from 1983 through 2004 in the System
Planning, Bulk Power Marketing and Operations Groups. In 2004 he joined Ameren Services
where he is currently a Transmission Planning Consulting Engineer. Rick has over 28 years of
experience in the Planning and Bulk Power Marketing area and is actively involved in several
SERC subcommittees and working groups. His main areas of interest are power system
planning and voltage, steady state, small signal and transient stability.
Venkat (Sharma) Kolluri: Sharma has a MSEE from West Virginia University, Morgantown and
an MBA from University of Dayton. He worked for AEP Service Corporation in Columbus, Ohio
from 1977 through 1984 in the Bulk Transmission Planning Group. In 1984 he joined Entergy
Services Inc., where he is currently the Manager of Transmission Planning. Sharma has over 25
years of experience in Planning and Operations area and is actively involved in several IEEE
subcommittees, NERC Standards Development Task Forces, and CIGRE working groups. His
main areas of interest are power system planning and operations, voltage and dynamic stability,
and reactive power planning. Sharma was recently selected as IEEE Fellow for innovative
contributions to the stability area.
Greg Davis: Greg received a Bachelor of Science in Electrical Engineering from North Carolina
Agricultural & Technical State University, Greensboro NC in 1996. He has worked for Georgia
Transmission Corporation (GTC) from 2000 to the present. From 2000-2003 Greg began his
career as a Test Engineer working in Substation Maintenance. In 2004 he started working in
the System Protection Department, working as a regional Protection Engineer. Greg is currently
the ERO Compliance Specialist for the P&C Department, where he serves as the subject matter
expert for PRC standards and represents the Corporation on internal and external teams,
committees and industry groups.
Ernesto Paon: Ernesto has a BSEE from the University of Illinois, Champaign-Urbana, Illinois,
and completed graduate work towards MSEE from Iowa State University, Ames, Iowa. He
worked for Illinois Power Company from 1975 through 1985 in the substation design and system
protection departments. He worked for LEMCO / Y&A Consulting Engineers in St. Louis,
Missouri from 1985 through 1988 as a project engineer. In 1988 he joined the Municipal Electric
Authority of Georgia where he is currently the Manager of System Protection and Testing.
Ernesto has over 33 years experience in protection & control. He is a member of IEEE.
John O'Connor: John O’Connor has over 30 years of experience in the operation, maintenance
and engineering of electric power systems. He graduated from N.C. State University with a BS
in Electrical Engineering, is a registered professional engineer in North Carolina, and holds an
electrical contractor license. John is currently a Principal Engineer in Progress Energy
Carolinas’ Transmission Planning group, where he is responsible for stability studies.

September 19, 2011

Page 3

Bob Jones: Bob is currently the Planning Manager for Stability and Special Studies in the
Transmission Planning Department at Southern Company Services. Bob obtained a BSEE
degree from the University of Alabama in 1973 and an MSEE degree from University of
Alabama – Birmingham in 1978. He has worked for 38 years for Southern Company Services.
Earlier in his career, Bob was involved in transient voltage analysis, harmonics studies, power
quality, and surge protection. For the last 17 years, he has worked in Transmission Planning
and has been responsible for stability studies for the Southern Company.
Jonathan Glidewell: Jonathan is currently a Project Manager in Transmission Planning with
Southern Company Services. Jonathan began working in the Transmission Planning
Department as an Engineer in 2001. He has worked in Transmission Planning since 2001
except for one year during 2008 – 2009 where he worked in Operations Planning. His main
areas of interest are power system planning and operations, voltage and dynamic stability, and
reactive power planning. Jonathan received a Bachelor of Science in Electrical and Computer
Engineering from the University of Alabama at Birmingham in 2001 and is a registered
Professional Engineer in the state of Alabama.
Tom Cain: Tom obtained a BS in Engineering Physics at Cornell University and then an MSEE
degree from Georgia Tech. Tom worked for GM and the Southwest Research Institute before
coming to TVA in 1994. Tom has been working in the Transmission Planning Department since
in 1999 where he has been responsible for stability studies.
Andrew Fusco: Andrew is the Manager of Planning at ElectriCities of North Carolina, Inc. In
his role at ElectriCities, Andrew is responsible resource planning, load forecasting, transmission
planning, renewable energy strategy, and compliance with NERC Reliability Standards. He has
10 years of electric utility experience and 18 years of professional experience, which includes
experience with nuclear facilities at Los Alamos National Laboratory. Andrew has served on a
number of NERC and SERC Committees including the NERC Planning Committee, the NERC
Compliance and Certification Committee, the SERC Engineering Committee, and the SERC
Reliability Review Subcommittee. Andrew holds Bachelor and Master of Science Degrees from
the Massachusetts Institute of Technology and a Master of Business Administration from Duke
University.
Anthony Williams: Anthony is a Senior Engineer at Duke Energy where he specializes in
dynamic studies and transmission system reactive power studies. He is a registered
Professional Engineer with 12 years Transmission Planning experience and over 20 years of
power system experience. Anthony has served in various positions on several inter-utility
groups including the SERC Dynamics Review Subcommittee, the SERC Intra-Regional
Dynamics Study Group and the VACAR Stability Working Group. During his Transmission
Planning career, Anthony provided project leadership and technical expertise on several large
projects including generator testing, SVC sizing studies, and automating transmission study
processes.
Pat Huntley: Pat is currently the Manager, Reliability Standards with SERC Reliability
Corporation. Pat joined SERC in 2000 and provided support to the Engineering Committee for
seven years. Pat had the lead in drafting the SERC Regional Reliability Standards Development
Procedure, which became part of the Regional Entity delegation between SERC and NERC. Pat
September 19, 2011

Page 4

moved to his current position when SERC transitioned to a Regional Entity. He serves as the
SERC representative on the ERO Regional Standards Group and serves on the
Communications and Planning Subcommittee of the NERC Standards Committee. Prior to
joining SERC, Pat worked for Duke Energy for 30 years and retired in 1999. He started in field
transmission operations and served in a number of positions including transmission power
quality supervisor, System Operating engineer, and Manager of Transmission Planning. Pat
received a Bachelor of Science in Electrical Engineering from Clemson University in 1968, a
Master of Engineering in Electrical Engineering in 1979, and is a registered Professional
Engineer in the states of NC and SC.

September 19, 2011

Page 5

Exhibit E
PRC-006-SERC-01 – Violation Severity Level and Violation Risk Factor Analysis

SERC Regional UFLS Standard (PRC-006-SERC-01)
VRF and VSL Justification
This document provides the justification for assignment of VRFs and VSLs, identifying how each
proposed VRF and VSL meets NERC’s criteria and FERC’s Guidelines. NERC’s criteria for
setting VRFs and VSLs; FERC’s five guidelines (G1 – G5) for approving VRFs; and FERC’s four
guidelines (G1-G4) for setting VSLs are provided at the end of this document.

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
September 19, 2011

Medium
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
This requirement specifies that the Planning Coordinator shall
include its SERC subregion(s) as an identified island in the
design of its UFLS scheme. This in turn requires simulation of
the subregion to verify that it meets the performance
characteristics specified in R3 of PRC-006-1. Failure to comply
with this requirement could allow a poorly performing UFLS
scheme or a UFLS scheme that does not coordinate well with
others in the subregion to go undetected.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
The VRF assigned to this requirement is consistent with the
VRF assignment to R2 (part 2.3) of PRC-006-1 which
addresses a similar reliability goal.
Guideline 4- Consistency with NERC Definitions of VRFs
Page 1

Discussion

FERC VRF G5
Discussion

Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does not comingle a higher risk reliability
objective and a lesser risk reliability objective.

Proposed Lower
VSL

N/A

Proposed Moderate
VSL

N/A

Proposed High VSL

N/A

Proposed Severe
VSL

The Planning Coordinator did not have evidence that its criteria
included selection of its SERC subregion(s) as an island, with
or without adjusted boundaries.
This is a binary requirement. Therefore, the VSL is Severe for
failure to perform.
The VSL assignment complies with Guideline 1 because it
does not have the unintended consequence of lowering the
current or historic level of compliance.

VSL Discussion
FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

FERC VSL G2
Violation Severity
Level Assignments
Should Ensure
Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The
Single Violation
Severity Level
Assignment Category
for "Binary"
Requirements Is Not
Consistent
Guideline 2b: Violation
Severity Level
September 19, 2011

This is a binary requirement. The VSL for failure to perform is
Severe in compliance with Guideline 2A. The VSL is written in
clear and unambiguous language in compliance with Guideline
2B.

Page 2

Assignments that
Contain Ambiguous
Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment is consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignment complies with Guideline 4, because it is
based on a single violation of a Reliability Standard and is not
based on a cumulative number of violations of the same
requirement over a period of time.

Page 3

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

September 19, 2011

Medium
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
This requirement sets minimum requirements for the Planning
Coordinator UFLS scheme. Failure to comply with this
requirement could result in a lack of consistency and poor
coordination for the various UFLS schemes which are used in
SERC
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
The VRF assigned to this requirement is consistent with the
VRF assignment to R5 of PRC-006-1 which addresses a
similar reliability goal.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
Page 4

FERC VRF G5
Discussion

Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does not comingle a higher risk reliability
objective and a lesser risk reliability objective.

Proposed Lower
VSL

The Planning Coordinator's scheme did not meet one of the
UFLS system design requirements identified in 2.2 through 2.6
The Planning Coordinator's scheme did not meet two of the
UFLS system design requirements identified in 2.2 through 2.6.

Proposed Moderate
VSL
Proposed High VSL
Proposed Severe
VSL

VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

The Planning Coordinator's scheme did not meet three of the
UFLS system design requirements identified in 2.2 through 2.6.
The Planning Coordinator's scheme did not meet 2.1
OR
Four or more of the UFLS system design requirements
identified in 2.2 through 2.6.
This requirement has multiple parts. Part 2.1 is considered to
be more important and Parts 2.2 through 2.6 contribute
relatively equally to meeting the requirement. Therefore, the
VSLs are based on the number of parts missing. Missing one
of Parts 2.2 through 2.6 is Lower. Missing two of Parts 2.2
through 2.6 is Moderate. Missing three of Parts 2.2 through 2.6
is High. Missing Part 2.1 or four or more of Parts 2.1 through
2.6 is Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 5

Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment(s) are consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 6

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

FERC VRF G5
Discussion

September 19, 2011

High
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading
failures, or could hinder restoration to a normal condition.
This requirement specifies simulation of the UFLS scheme that
the Planning Coordinator must conduct to satisfy R4 of PRC006-1. Failure to comply with this requirement could result in a
UFLS scheme that does not meet the performance
requirements specified in R3 of the NERC UFLS standard
(PRC-001-1) for all imbalance conditions between load and
generation of up to 25%.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirements.
Guideline 3- Consistency among Reliability Standards
The VRF assigned to this requirement is consistent with the
VRF assignment to R3 of PRC-006-1 which addresses a
similar reliability goal.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading
failures, or could hinder restoration to a normal condition.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement comingles a higher risk reliability objective
(High for 25% imbalance simulation) and lesser risk reliability
objectives (Medium for 13% and 22% imbalance simulations).
Page 7

Proposed Lower
VSL

N/A

Proposed Moderate
VSL

The Planning Coordinator failed to conduct one of the required
simulations of its UFLS scheme.

Proposed High VSL

N/A
The Planning Coordinator failed to conduct two of the required
simulations of its UFLS scheme.

Proposed Severe
VSL
VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

September 19, 2011

There are at least six simulations required - a minimum of two
islands and three imbalance levels. Each simulation
contributes relatively equally to meeting the requirement.
Therefore, the VSLs are based on the number of simulations
missing. Missing one simulation is considered to be Moderate.
Missing two or more simulations is considered to be Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 8

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 9

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

September 19, 2011

Medium
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
This requirement specifies the tolerances for implementation of
the UFLS scheme by UFLS entities that have a total load of
100 MW or greater in a Planning Coordinator area in the SERC
Region. Failure to comply with this requirement could result in
a degradation of the expected performance of the UFLS
scheme.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
This requirement is consistent with R9 of PRC-006-1 which
addresses a similar reliability goal and has a VRF of “High.”
However, while R9 of PRC-006-1 requires implementation, this
requirement only addresses the tolerance for implementation. It
is therefore assigned a “Medium” VRF.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
Page 10

FERC VRF G5
Discussion

Proposed Lower
VSL
Proposed Moderate
VSL
Proposed High VSL

Proposed Severe
VSL

VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

FERC VSL G2
Violation Severity
Level Assignments
Should Ensure
Uniformity and
Consistency in the
Determination of
Penalties
Guideline 2a: The
Single Violation
September 19, 2011

separation, or cascading failures, nor to hinder restoration to a
normal condition.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does not comingle a higher risk reliability
objective and a lesser risk reliability objective.
The UFLS entity’s implemented UFLS scheme had one load
shedding step outside the range specified in 4.2.
The UFLS entity’s implemented UFLS scheme had two load
shedding steps outside the range specified in 4.2.
The UFLS entity’s implemented UFLS scheme had three or
more load shedding steps outside the range specified in 4.2.
OR
The UFLS entity's implemented UFLS scheme had a total load
outside the range specified in 4.3.
The UFLS entity’s implemented UFLS scheme had three or
more load shedding steps outside the range specified in 4.2.
AND
The UFLS entity's implemented UFLS scheme had a total load
outside the range specified in 4.3.
There are ranges set for the three load shedding steps
required and for the total amount of load. The ranges on the
three steps contribute relatively equally to meeting the
requirement. The range on the total amount of load is
considered to be more important. Therefore, having one step
out of range is considered to be Lower. Having two steps out of
range is considered to be Moderate. Having three steps out of
range or the total amount out of range is considered to be
High. Having three steps out of range and the total amount out
of range is considered to be Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 11

Severity Level
Assignment Category
for "Binary"
Requirements Is Not
Consistent
Guideline 2b: Violation
Severity Level
Assignments that
Contain Ambiguous
Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment(s) are consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 12

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

September 19, 2011

Medium
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
This requirement specifies the tolerances for implementation of
the UFLS scheme by UFLS entities that have a total load less
than 100 MW in a Planning Coordinator area in the SERC
Region. Failure to comply with this requirement could result in
some degradation of the expected performance of the UFLS
scheme.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
This requirement is consistent with R9 of PRC-006-1 which
addresses a similar reliability goal and has a VRF of “High.”
However, while R9 of PRC-006-1 requires implementation, this
requirement only addresses the tolerance for implementation. It
is therefore assigned a “Medium” VRF.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead directly to bulk electric system instability,
Page 13

FERC VRF G5
Discussion

Proposed Lower
VSL

N/A

Proposed Moderate
VSL

N/A

Proposed High VSL

N/A
The UFLS entity's implemented UFLS scheme had a total load
outside the range specified in 5.2.

Proposed Severe
VSL
VSL Discussion
FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
September 19, 2011

This is a binary requirement. Therefore, the VSL is Severe for
failure to perform.
The VSL assignment complies with Guideline 1 because it
does not have the unintended consequence of lowering the
current or historic level of compliance.

This is a binary requirement. The VSL for failure to perform is
Severe in compliance with Guideline 2A. The VSL is written in
clear and unambiguous language in compliance with Guideline
2B.

Corresponding
Requirement

objectively and with certainty.

FERC VSL G4

The VSL assignment complies with Guideline 4, because it is
based on a single violation of a Reliability Standard and is not
based on a cumulative number of violations of the same
requirement over a period of time.

Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

Page 15

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

September 19, 2011

Medium
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
normal condition.
This requirement specifies the maximum time for a UFLS entity
to complete implementation of a major change in a Planning
Coordinator’s UFLS scheme. Failure to comply with this
requirement could result in degradation of the expected
performance of the UFLS scheme.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirements.
Guideline 3- Consistency among Reliability Standards
This requirement is consistent with R9 of PRC-006-1 which
addresses a similar reliability goal. However, while R9 of PRC006-1 addresses UFLS scheme implementation and has a
VRF of “High,” this requirement only addresses the timing of
implementation. It therefore is assigned a “Medium” VRF.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement could, under emergency,
abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. However,
violation of this requirement is unlikely, under emergency,
abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a
Page 16

FERC VRF G5
Discussion

Proposed Lower
VSL
Proposed Moderate
VSL
Proposed High VSL
Proposed Severe
VSL

VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

normal condition.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does comingle a higher risk reliability
objective and a lesser risk reliability objective.
The UFLS entity implemented required scheme changes but
made them 1 to 30 days after the scheduled date.
The UFLS entity implemented required scheme changes but
made them 31 to 40 days after the scheduled date.
The UFLS entity implemented required scheme changes but
made them 41 to 50 days after the scheduled date.
The UFLS entity implemented required scheme changes but
made them more than 50 days after the scheduled date
OR
The UFLS entity failed to implement the required scheme
changes.
This requirement is based on meeting a schedule. Therefore,
the VSLs are based on number of days late. Missing the
schedule by up to 30 days is Lower. Missing the schedule by
31 - 40 days is Moderate. Missing the schedule by 41 - 50 days
is High. Missing the schedule by more than 50 days or failed to
implement the required scheme changes is Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 17

Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment(s) are consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 18

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

R7
FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

FERC VRF G5
Discussion

Proposed Lower
VSL
Proposed Moderate
September 19, 2011

Lower
Violation of this requirement would not, under the emergency,
abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system.
This is a planning requirement that is administrative in nature.
This requirement specifies UFLS implementation data that the
Planning Coordinator must supply to SERC. This will be used
to maintain a database for post-event analysis of frequency
disturbances. Failure to comply with this requirement could
result in a delay in performing post-event analysis of frequency
disturbances.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
The VRF assigned to this requirement is consistent with the
VRF assignment to R6, R7, and R8 of PRC-006-1 which
addresses a similar reliability goal.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement would not, under the emergency,
abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system.
This is a planning requirement that is administrative in nature.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does not comingle a higher risk reliability
objective and a lesser risk reliability objective.
The Planning Coordinator provided the data required in R7 to
SERC 1 to 10 days after the scheduled submittal date.
The Planning Coordinator provided the data required in R7 to
Page 19

VSL

Proposed High VSL

Proposed Severe
VSL

VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

SERC 11 to 20 days after the scheduled submittal date.
OR
The Planning Coordinator did not provide to SERC one piece
of information listed in R7.
The Planning Coordinator provided the data required in R7 to
SERC 21 to 30 days after the scheduled submittal date.
OR
The Planning Coordinator did not provide to SERC two pieces
of information listed in R7.
The Planning Coordinator provided the data required in R7 to
SERC more than 30 days after the scheduled submittal date.
OR
The Planning Coordinator did not provide to SERC any of the
information listed in R7.
This requirement has timing elements associated with meeting
it and has multiple parts that contribute relatively equally to
meeting it. Therefore, the VSLs have one component based on
number of days late and it has another component based on
the number of parts missing. The SDT thought that missing
one part was more significant than being up to 10 days late.
Therefore, missing the schedule by up to 10 days is Lower.
Missing one part or missing the schedule by 11 - 20 days is
Moderate. Missing two parts or missing the schedule by 21 - 30
days is High. Missing all three parts or missing the schedule by
more than 30 days is Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 20

Assignments that
Contain Ambiguous
Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment(s) are consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 21

VRF and VSL Justifications
Proposed VRF
NERC VRF
Discussion

FERC VRF G1
Discussion

R8
FERC VRF G2
Discussion
FERC VRF G3
Discussion

FERC VRF G4
Discussion

FERC VRF G5
Discussion

Proposed Lower
VSL
Proposed Moderate
September 19, 2011

Lower
Violation of this requirement would not, under the emergency,
abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system.
This is a planning requirement that is administrative in nature.
This requirement specifies generator underfrequency and
overfrequency protection data that the Generator Owner must
supply to SERC. This will be to facilitate post-event analysis of
frequency disturbances. Failure to comply with this requirement
could result in a delay in performing post-event analysis of
frequency disturbances.
Guideline 1- Consistency w/ Blackout Report
The team did not address Guideline 1 directly because of an
apparent conflict between Guidelines 1 and 4. Whereas
Guideline 1 identifies a list of topics that encompass nearly all
topics within NERC’s Reliability Standards and implies that
these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of
a specific requirement to the reliability of the system. The SDT
believes that Guideline 4 is reflective of the intent of VRFs and
therefore concentrated its approach on the reliability impact of
the requirements.
Guideline 2- Consistency within a Reliability Standard
This guideline is not applicable since this requirement does not
have sub-requirement VRF assignments.
Guideline 3- Consistency among Reliability Standards
The VRF assigned to this requirement is consistent with the
VRF assignment to R6, R7, and R8 of PRC-006-1 which
addresses a similar reliability goal.
Guideline 4- Consistency with NERC Definitions of VRFs
Violation of this requirement would not, under the emergency,
abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system.
This is a planning requirement that is administrative in nature.
Guideline 5- Treatment of Requirements that Co-mingle More
than One Obligation
This requirement does not comingle a higher risk reliability
objective and a lesser risk reliability objective.
The Generator Owner provided the data required in R8 to
SERC 1 to 10 days after the requested submittal date.
The Generator Owner provided the data required in R8 to
Page 22

VSL

Proposed High VSL

Proposed Severe
VSL

VSL Discussion

FERC VSL G1
Violation Severity
Level Assignments
Should Not Have the
Unintended
Consequence of
Lowering the Current
Level of Compliance

SERC 11 to 20 days after the requested submittal date.
OR
The Generator Owner did not provide to SERC one piece of
information listed in R8.
The Generator Owner provided the data required in R8 to
SERC 21 to 30 days after the requested submittal date.
OR
The Generator Owner did not provide to SERC two pieces of
information listed in R8.
The Generator Owner provided the data required in R8 to
SERC more than 30 days after the requested submittal date.
OR
The Generator Owner did not provide to SERC any of the
information listed in R8.
This requirement has timing elements associated with meeting
it and has multiple parts that contribute relatively equally to
meeting it. Therefore, the VSLs have one component based on
number of days late and it has another component based on
the number of parts missing. The SDT thought that missing
one part was more significant than being up to 10 days late.
Therefore, missing the requested submittal date by up to 10
days is Lower. Missing one part or missing the requested
submittal date by 11 - 20 days is Moderate. Missing two parts
or missing the requested submittal date by 21 - 30 days is
High. Missing three parts or missing the requested submittal
date by more than 30 days is Severe.
The VSL assignments comply with Guideline 1 because they
do not have the unintended consequence of lowering the
current or historic level of compliance.

This is not a binary requirement, therefore Guideline 2A does
not apply. The VSL is written in clear and unambiguous
language in compliance with Guideline 2B.

Page 23

Severity Level
Assignments that
Contain Ambiguous
Language

FERC VSL G3
Violation Severity
Level Assignment
Should Be Consistent
with the
Corresponding
Requirement

FERC VSL G4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations

September 19, 2011

The VSL aligns with the language of the requirement, and does
not add to nor take away from it. The VSL does not redefine or
undermine the requirement’s reliability goal. In accordance
with Guideline 3, the VSL assignment(s) are consistent with the
requirement and the degree of compliance can be determined
objectively and with certainty.
The VSL assignments comply with Guideline 4, because they
are based on a single violation of a Reliability Standard and are
not based on a cumulative number of violations of the same
requirement over a period of time.

Page 24

NERC’s VRF Criteria:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a requirement
in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC’s VRF Guidelines:
VRF G1 – Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact
on the reliability of the Bulk-Power System. From footnote 15 of the May 18, 2007 Order,
FERC’s list of critical areas (from the Final Blackout Report) where violations could severely
affect the reliability of the Bulk-Power System includes:
− Emergency operations
− Vegetation management
− Operator personnel training
− Protection systems and their coordination
− Operating tools and backup facilities
− Reactive power and voltage control
− System modeling and data exchange
− Communication protocol and facilities
− Requirements to determine equipment ratings
September 19, 2011

Page 25

−
−
−

Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.

VRF G2 – Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk
Factor assignments and the main Requirement Violation Risk Factor assignment.
VRF G3 – Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be
treated comparably.
VRF G4 – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
VRF G5 –Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk
reliability objective, the VRF assignment for such Requirements must not be watered down to
reflect the lower risk level associated with the less important objective of the Reliability
Standard.
NERC’s Criteria for VSLs:
Lower VSL
The performance or
product measured
almost meets the full
intent of the
requirement.

Moderate VSL
The performance or
product measured
meets the majority of
the intent of the
requirement.

High VSL

Severe VSL

The performance or
product measured does
not meet the majority of
the intent of the
requirement, but does
meet some of the
intent.

The performance or
product measured does
not substantively meet
the intent of the
requirement.

FERC’s VSL Guidelines:
VSL G1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance (Compare the VSLs to any prior
Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.)
VSL G2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties (A violation of a “binary” type requirement
must be a “Severe” VSL. Avoid using ambiguous terms such as “minor” and “significant” to
describe noncompliant performance.)
VSL G3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement (VSLs should not expand on what is required in the
requirement.)
September 19, 2011

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VSL G4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not
on A Cumulative Number of Violations (. . . unless otherwise stated in the requirement, each
instance of non-compliance with a requirement is a separate violation. Section 4 of the Sanction
Guidelines states that assessing penalties on a per violation per day basis is the “default” for
penalty calculations.)

September 19, 2011

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File Type	application/pdf
Author	Karen Spolar
File Modified	2012-02-01
File Created	2012-02-01